-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Bx82jviTmycRH1SVJ40S55Unh6BRD+TOCEGjGXfkqyBL5ymn4ZZW2MTl/A0Uv386 b9r8K41OA8mu8REoQkDBwg== 0000899078-97-000054.txt : 19970321 0000899078-97-000054.hdr.sgml : 19970321 ACCESSION NUMBER: 0000899078-97-000054 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970320 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: DENBURY RESOURCES INC CENTRAL INDEX KEY: 0000945764 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 033-93722 FILM NUMBER: 97559744 BUSINESS ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 BUSINESS PHONE: 2147133000 MAIL ADDRESS: STREET 1: 17304 PRESTON RD STREET 2: STE 200 CITY: DALLAS STATE: TX ZIP: 75252 FORMER COMPANY: FORMER CONFORMED NAME: NEWSCOPE RESOURCES LTD DATE OF NAME CHANGE: 19950627 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from _________ to________ COMMISSION FILE NUMBER 33-93722 DENBURY RESOURCES INC. (Exact name of Registrant as specified in its charter) CANADA NOT APPLICABLE (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 17304 PRESTON RD., SUITE 200 DALLAS, TX 75252 (Address of principal executive offices) (Zipcode) Registrant's telephone number, including area code: (972)713-3000 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - ----------------------------------- -------------------------------------------- Common Shares ( No Par Value) NASDAQ =================================== ============================================ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x/ No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of March 17, 1997, the aggregate market value of the registrant's Common Shares held by non-affiliates was approximately $140,000,000. The number of shares outstanding of the registrant's Common Shares as of March 17, 1997, was 20,101,607. DOCUMENTS INCORPORATED BY REFERENCE DOCUMENT INCORPORATED AS TO 1. Notice and Proxy Statement 1. Part III, Items 10, 11, 12, and 13 for the Annual Meeting of Shareholders to be held May 21, 1997 2. Annual Report to Shareholders 2. Part I, Item 1 and Part II, for the year ended Items 5, 6, 7, 8 December 31, 1996 PART I ITEM 1. BUSINESS THE COMPANY Denbury Resources Inc. ("Denbury" or the "Company") is a Canadian corporation organized under the Canada Business Corporations Act engaged in the acquisition, development, operation and exploration of oil and gas properties primarily in the Gulf Coast region of the United States through its indirectly wholly-owned subsidiary, Denbury Management, Inc., a Texas corporation. Denbury's corporate headquarters is located at Suite 200, 17304 Preston Road, Dallas, Texas 75252, U.S.A. and its Canadian office is located at 2550, 140--4th Avenue S.W., Calgary, Alberta T2P 3N3. At December 31, 1996, the Company had 122 employees, 56 of which were employed in field operations. Incorporation and Organization Denbury was originally incorporated under the laws of Manitoba as a specially limited company on March 7, 1951, under the name "Kay Lake Mines Limited (N.P.L.)". In September 1984, the Company was continued under the Canada Business Corporations Act and changed its name to "Newscope Resources Limited." The Company has subsequently changed its name three times, including the most recent change in December, 1995 from "Newscope Resources Ltd." to its current name of "Denbury Resources Inc.". The Company has one wholly owned subsidiary, Denbury Holdings Ltd. ("Denbury Holdings"), which in turn has one wholly owned subsidiary, Denbury Management, Inc. ("Denbury Management"). Denbury Holdings carries on no material business other than the holding of 100% of the outstanding shares of the capital stock of Denbury Management. Denbury Management has two active wholly owned subsidiaries, Denbury Marine, L.L.C. and Brymore Energy Corporation. The Company's consolidated financial statements include the accounts of the parent company and all wholly owned subsidiaries. History The Company acquired all of the outstanding shares of Denbury Management in a multi-step transaction in July 1992, in exchange for 2,771,530 Common Shares (the "Denbury Acquisition"). Upon completion of the Denbury Acquisition, Mr. Gareth Roberts, the then president of Denbury Management, was appointed the President and Chief Executive Officer of the Company and was elected to the Company's board of directors. He has served in that capacity since that time. The Denbury Acquisition signaled a new direction for the Company and added a new geographic area of operation (the states of Texas, Louisiana and Mississippi), and management expertise to the Company. Prior to 1987, the Company's activities were focused in Manitoba and to a lesser extent, Saskatchewan. During the years 1988, 1989 and 1990, most of Denbury's exploration and development program was conducted in Alberta and during this period, the Company generated and operated most of its exploration prospects. Effective March 31, 1992, Denbury's Manitoba oil and gas properties were sold for net proceeds of approximately $1.2 million. In September 1993, Denbury sold all of its remaining Canadian oil and gas operations for approximately $3.1 million. These operations consisted primarily of Denbury's producing oil and gas properties in Saskatchewan and Alberta, undeveloped lands in the provinces of British Columbia, Alberta, Saskatchewan, and a seismic data base. As a result, 100% of Denbury's oil and gas operations are now conducted in the Southern United States through its subsidiary, Denbury Management. Since 1993, after having disposed of its Canadian oil and natural gas properties, the Company has focused its operations primarily onshore in Louisiana and Mississippi. Over the last three years, the Company has achieved rapid growth in proved reserves, production and cash flow by concentrating on the acquisition of properties which it believes have significant upside potential and through the efficient development, enhancement and operation of those properties. 1 1996 CAPITAL ADJUSTMENTS During 1996, the Company issued 250,000 Common Shares for the conversion of its 6 3/4% Convertible Debentures and 75,000 Common Shares for the exercise of half of its Cdn. $8.40 Warrants. On October 10, 1996, the Company effected a one-for-two reverse split of its outstanding Common Shares and effective October 15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures ("Debentures") were converted by their holders into 316,590 Common Shares. At a special meeting held on October 9, 1996 the shareholders of the Company approved an amendment to the terms of the Convertible First Preferred Shares, Series A ("Convertible Preferred") to allow the Company to require the conversion of the Convertible Preferred at any time, provided that the conversion rate in effect as of January 1, 1999 would apply to any required conversion prior to that date. The Company converted all of the 1,500,000 shares of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at a net price to the Company of $12.035 per share as part of a public offering with net proceeds to the Company of approximately $58.8 million (the "Public Offering"). The Company's largest shareholder, the Texas Pacific Group ("TPG"), purchased 800,000 of these shares at $12.035 per share. BUSINESS STRATEGY The Company believes that its growth to date in proved reserves, production and cash flow is a direct result of its adherence to several fundamental principles. The Company seeks to achieve attractive returns on capital through prudent acquisitions, development and exploratory drilling and efficient operations; maintain a conservative balance sheet to preserve maximum financial and operational flexibility; and create strong employee incentives through equity ownership. These fundamental principles are at the core of the Company's long-term growth strategy. REGIONAL FOCUS. By focusing its efforts in the Gulf Coast region, primarily Louisiana and Mississippi, the Company has been able to accumulate substantial geological, reservoir and operating data which it believes provides it with a significant competitive advantage. Given its experience in the Gulf Coast region, the Company believes it is better able to proactively identify and evaluate potential acquisitions, negotiate and close selected acquisitions on favorable terms, and develop and operate the properties in an efficient and low-cost manner once acquired. The Company believes the Gulf Coast represents one of the most attractive regions in North America given the region's prolific production history and the new opportunities that have been created by advanced technologies such as 3-D seismic and various drilling, completion and recovery techniques. Moreover, because of the region's proximity to major pipeline networks serving attractive northeastern U.S. markets, the Company typically realizes natural gas prices in excess of those realized in many other producing regions. DISCIPLINED ACQUISITION STRATEGY. The Company acquires properties where it believes significant additional value can be created. Such properties are typically characterized by: (i) long production histories; (ii) complex geological formations which have multiple producing zones and substantial exploitation potential; (iii) a history of limited operational attention and capital investment, often due to their relatively small size and limited strategic importance to the previous owner; and (iv) the potential for the Company to gain control of operations. By maintaining conservative levels of debt, the Company is able to respond quickly to acquisitions that fit within its criteria. The Company believes that due to continuing rationalization of properties, primarily by major integrated and independent energy companies, a strong backlog of acquisition opportunities should continue. In addition, the Company seeks to maintain a well-balanced portfolio of oil and natural gas development, exploitation and exploration projects in order to minimize the overall risk profile of its investment opportunities while still providing significant upside potential. The Company's recent Hess and Ottawa Acquisitions are illustrative of the type of opportunities the Company seeks. OPERATION OF HIGH WORKING INTEREST PROPERTIES. The Company typically seeks to acquire working interest positions that give the Company operational control or which the Company believes may lead to operational control. As the operator of properties comprising approximately two-thirds of its total PV10 Value, the Company is better able to manage and monitor production and more effectively control expenses, the allocation of capital and the timing of field development. Once a property is acquired, the Company employs its technical and operational expertise in fully evaluating a field for 2 future potential and, if favorable, consolidates working interest positions primarily through negotiated transactions which tend to be attractively priced compared to acquisitions available in competitive situations. The consolidation of ownership allows the Company to: (i) enhance the effectiveness of its technical staff by concentrating on relatively few wells; (ii) increase production while adding virtually no additional personnel; and (iii) increase ownership in a property to the point where the potential benefits of value enhancement activities justify the allocation of Company resources. EXPLOITATION OF PROPERTIES. The Company seeks to maximize the value of its properties by either increasing production, increasing recoverable reserves or reducing operating costs, and often through a combination of all three. The Company utilizes a variety of techniques to achieve this goal, including: (i) undertaking surface improvements such as rationalizing, upgrading or redesigning production facilities; (ii) making downhole improvements such as resizing downhole pumps or reperforating existing production zones; (iii) reworking existing wells into new production zones with additional potential; (iv) conducting developmental drilling to access undrained portions of the field which can only be produced from a new wellbore; and (v) utilizing exploratory drilling, which is frequently based on various advanced technologies such as 3-D seismic. The Company believes that by employing a full range of value enhancement techniques it is better able to extract the maximum value from its properties. PERSONNEL. The Company believes it has assembled a highly competitive team of experienced and technically proficient employees who are motivated through a positive work environment and by ownership in the Company, which is encouraged through the Company's stock option and stock purchase plans. The Company's geological and engineering professionals have an average of over 15 years of experience in the Gulf Coast region. The Company believes that employee ownership is essential for attracting, retaining and motivating quality personnel. Approximately 96% of Denbury's eligible employees were participating in the Company's stock purchase plan as of December 31, 1996. ACQUISITIONS OF OIL AND GAS PROPERTIES Information as to recent acquisitions by the Company is set forth under Acquisition of Oil and Natural Gas Properties, appearing on pages 10 through 11 of the Annual Report. Such information is incorporated herein by reference. OIL AND GAS OPERATIONS Information regarding selected operating data and a discussion of the Company's two significant operating areas and the primary properties within those two areas is set forth under Selected Operating Data, Oil and Natural Gas Operations, Louisiana Operations and Mississippi Operations, appearing on pages 8 and 9 and pages 11 through 20 of the Annual Report. Such information is incorporated herein by reference. Oil and Gas Acreage The following table sets forth Denbury's acreage position at December 31, 1996:
DEVELOPED UNDEVELOPED ----------------------------------- --------------------------------- GROSS NET GROSS NET --------------- --------------- --------------- ------------- Louisiana 29,328 20,374 10,137 7,812 Mississippi 17,511 11,138 19,180 8,002 Other 1,710 1,260 1,709 722 --------------- --------------- --------------- ------------- Total 48,549 32,772 31,026 16,536 =============== =============== =============== =============
3 Productive Wells This table sets forth both the gross and net productive wells at December 31, 1996:
PRODUCING OIL WELLS PRODUCING GAS WELLS TOTAL --------------------------- --------------------------- ------------------------- GROSS NET GROSS NET GROSS NET ----------- ---------- ----------- ----------- ---------- ---------- Louisiana 44 24.8 66 38.1 110 62.9 Mississippi 142 106.0 28 14.8 170 120.8 Other 4 2.0 12 5.3 16 7.3 ----------- ---------- ----------- ----------- ---------- ---------- Total 190 132.8 106 58.2 296 191.0 =========== ========== =========== =========== ========== ==========
Drilling Activity The following table sets forth the results of drilling activities during each of the three fiscal years in the period ended December 31, 1996.
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1996 1995 1994 ------------------- ------------------ ------------------- GROSS NET GROSS NET GROSS NET -------- -------- -------- -------- -------- -------- EXPLORATORY WELLS: Productive............................ - - - - - - Nonproductive......................... 1 1.0 2 1.0 3 0.8 DEVELOPMENT WELLS: Productive............................ 9 7.9 2 1.5 4 2.9 Nonproductive......................... - - - - 1 1.0 -------- -------- -------- -------- -------- -------- Total.................... 10 8.9 4 2.5 8 4.7 ======== ======== ======== ======== ======== ======== (1) An exploratory well is a well drilled either in search of a new, as-yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A developmental well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. (2) A producing well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. (3) A dry well is an exploratory or development well that is not a producing well.
There was one well in the process of drilling at December 31, 1996. TITLE TO PROPERTIES Customarily in the oil and gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired. Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects. During acquisitions, title reviews are performed on all properties; however, formal title opinions are obtained on only the higher value properties. PRODUCTION The following tables summarize sales volume, sales price and production cost information for the Company's net oil and gas production for each year of the three-year period ended December 31, 1996. "Net" production is production that is owned by the Company and produced for its interest after deducting royalties and other similar interests. 4
YEAR ENDED DECEMBER 31, -------------------------------------- 1996 1995 1994 ----------- ---------- ---------- NET PRODUCTION VOLUME Crude oil - (Mbbls) 1,500 728 489 Natural gas - (Mmcf) 8,933 4,844 3,326 Equivalent - MBOE (1) 2,989 1,535 1,043 AVERAGE SALES PRICE Crude oil - ($/bbl) $ 18.98 $ 14.90 $ 13.84 Natural gas - ($/Mcf) 2.73 1.90 1.78 Per equivalent BOE (1) 17.69 13.05 12.17 AVERAGE PRODUCTION COST Per equivalent BOE (1) $ 4.51 $ 4.42 $ 4.13 (1)Based on a 6 Mcf to 1 Bbl gas to oil conversion ratio.
SIGNIFICANT OIL AND GAS PURCHASERS Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon the Company. For the year ended December 31, 1996, the Company sold 10% or more of its net production of oil and gas to the following purchasers: Natural Gas Clearinghouse (20%), PennUnion Energy Services (19%), Enron Oil Trading & Transportation (13%), and Hunt Refining (15%). GEOGRAPHIC SEGMENTS All Canadian oil and gas properties were disposed of in 1993 and thus, all of the Company's operations are now in the United States. COMPETITION The oil and gas industry is highly competitive in all its phases. The Company encounters strong competition from many other oil and gas producers, in acquiring economically desirable producing properties and drilling prospects, and in obtaining equipment and labor to operate and maintain its properties. In addition, many producers possess larger staffs and greater financial resources than the Company. PRICE VOLATILITY The revenues generated by the Company are highly dependent upon the prices of oil and natural gas. The marketing of oil and natural gas is affected by numerous factors beyond the control of the Company. These factors include crude oil imports, the availability of adequate pipeline and other transportation facilities, the marketing of competitive fuels, and other factors affecting the availability of a ready market, such as fluctuating supply and demand. PRODUCT MARKETING Denbury's production is primarily from developed fields close to major pipelines or refineries and established infrastructure. As a result, Denbury has not experienced any difficulty in finding a market for all of its product as it becomes available or in transporting its product to these markets. 5 Oil Marketing Denbury markets its oil to a variety of purchasers, most of which are large, established companies. The oil is generally sold under a one-year contract with the sales price based on an applicable posted price, plus a negotiated premium. This price is determined on a well-by-well basis and the purchaser generally takes delivery at the wellhead. Mississippi oil, which accounted for approximately 73% of the Company's oil production in 1996, is primarily light sour crude and sells at a discount to the published West Texas Intermediate posting. The balance of the oil production, Louisiana oil, is primarily light sweet crude, which typically sells at a slight premium to the West Texas Intermediate posting. Natural Gas Marketing Virtually all of Denbury's natural gas production is close to existing pipelines and consequently, the Company generally has a variety of options to market its natural gas. The Company sells the majority of its natural gas on one year contracts with prices fluctuating month-to-month based on published pipeline indices with slight premiums or discounts to the index. Production Price Hedging For 1995, the Company entered into financial contracts to hedge 75% of the Company's net natural gas production and 43% of the Company's net oil production. The net effect of these hedges was to increase oil and natural gas revenues by approximately $750,000 during 1995. The Company did not have any hedge contracts in place as of December 31, 1996 although it may have such contracts in the future. REGULATIONS The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company's control. These factors include regulation of natural gas and oil production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by well or proration unit, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. The following discussion summarizes the regulation of the United States oil and gas industry and is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which the Company's operations may be subject. Regulation of Natural Gas and Oil Exploration and Production The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects 6 its profitability. Inasmuch as such laws and regulations are frequently expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. Federal Regulation of Sales and Transportation of Natural Gas Federal legislation and regulatory controls in the U.S. have historically affected the price of the natural gas produced by the Company and the manner in which such production is marketed. The Federal Energy Regulatory Commission (the "FERC") regulates the interstate transportation and sale for resale of natural gas by interstate and intrastate pipelines. The FERC previously regulated the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce under the Natural Gas Policy Act. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. As a result, all sales of the Company's domestically produced natural gas may be sold at market prices, unless otherwise committed by contract. The FERC's jurisdiction over natural gas transportation and gas sales other than first sales was unaffected by the Decontrol Act. The Company's natural gas sales are affected by the regulation of intrastate and interstate gas transportation. In an attempt to restructure the interstate pipeline industry with the goal of providing enhanced access to, and competition among, alternative natural gas supplies, the FERC, commencing in April 1992, issued Order Nos. 636, 636-A and 636-B ("Order No. 636") which have altered significantly the interstate transportation and sale of natural gas. Among other things, Order No. 636 required interstate pipelines to unbundle the various services that they had provided in the past, such as sales, transmission and storage, and to offer these services individually to their customers. By requiring interstate pipelines to "unbundle" their services and to provide their customers with direct access to pipeline capacity held by them, Order No. 636 has enabled pipeline customers to choose the levels of transportation and storage service they require, as well as to purchase natural gas directly from third-party merchants other than the pipelines and obtain transportation of such gas on a non-discriminatory basis. The effect of Order No. 636 has been to enable the Company to market its natural gas production to a wider variety of potential purchasers. The Company believes that these changes generally have improved the Company's access to transportation and have enhanced the marketability of its natural gas production. To date, Order No. 636 has not had any material adverse effect on the Company's ability to market and transport its natural gas production. However, the Company cannot predict what new regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on the Company's activities. In addition, Order No. 636 and a number of related orders were appealed. Recently, the United States Court of Appeals for the District of Columbia Circuit issued an opinion largely upholding the basic features and provision of Order No. 636. However, even though Order No. 636 itself has been judicially approved, several related FERC orders remain subject to pending appellate review and further changes could occur as a result of court order or at the FERC's own initiative. In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas. Some of the more notable of these regulatory initiatives include (i) a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate natural gas pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion of a rulemaking involving the regulation of interstate natural gas pipelines with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to promulgate standards for pipeline electronic bulletin boards and electronic data exchange, (iv) a generic inquiry into the pricing of interstate pipeline capacity, (v) efforts to refine FERC's regulations controlling the operation of the secondary market for released interstate natural gas pipeline capacity, and (vi) a policy statement regarding market-based rates and other non-cost-based rates for interstate pipeline transmission and storage capacity. Several of these initiatives are intended to enhance competition in natural gas markets. While any resulting FERC action would affect the Company only indirectly, the ongoing, or, in some instances, preliminary evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact upon the Company's activities. Oil Price Controls and Transportation Rates Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. Commencing in October 1993, the FERC has modified its regulation of oil pipeline rates and services in order to comply with the Energy Policy Act of 1992. That Act mandated the FERC to streamline oil pipeline ratemaking by 7 abandoning its old, cumbersome procedures and issue new procedures to be effective January 1, 1995. In response, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The FERC's new oil pipeline ratemaking methodology was recently affirmed by the Court. The Company is not able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on the transportation costs associated with oil production from the Company's oil producing operations. Environmental Regulations The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, the business and prospects of the Company could be adversely affected. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. The Company currently owns or leases numerous properties that for many years have been used for the exploration and production of oil and gas. Most of these properties have been operated by prior owners, operators and third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), Federal Resource Conservation and Recovery Act and analogous state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Certain provisions of CAA may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, the Company does not believe its operations will be materially adversely affected by any such requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including but not limited to, the costs of responding to a release of oil to surface waters. Regulations are currently being developed under the OPA and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. The Company also is subject to a variety of federal, state, and local permitting and registration requirements relating to protection of the environment. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. 8 TAXATION Since all of the Company's oil and natural gas operations are located in the United States, the Company's primary tax concerns relate to U.S. tax laws, rather than Canadian laws. Certain provisions of the United States Internal Revenue Code of 1986, as amended, are applicable to the petroleum industry. Current law permits the Company to deduct currently, rather than capitalize, intangible drilling and development costs ("IDC") incurred or borne by it. The Company, as an independent producer, is also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced by it (if such percentage of depletion exceeds cost depletion). Generally, this deduction is 15% of gross income from an oil and natural gas property, without reference to the taxpayer's basis in the property. Percentage depletion can not exceed the taxable income from any property (computed without allowance for depletion), and is limited in the aggregate to 65% of the Company's taxable income. Any depletion disallowed under the 65% limitation, however, may be carried over indefinitely. See Note 4 of the Consolidated Financial Statements for additional tax disclosures. ESTIMATED NET QUANTITIES OF PROVED OIL AND GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES Net proved oil and gas reserves as of December 31, 1996 and 1995, have been prepared by Netherland, Sewell and Associates, Inc. and the net oil and gas reserves as of December 31, 1994 were prepared by the Scotia Group, Inc., both independent petroleum engineers are located in Dallas, Texas. See Note 10 to the Consolidated Financial Statements for disclosure of reserve amounts. FORWARD-LOOKING INFORMATION The statements contained in this Annual Report on Form 10-K ("Annual Report") that are not historical facts, including, but not limited to, statements found in this Item 1. Business and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. The actual results of the future events described in such forward-looking statements in this Annual Report could differ materially from those stated in such forward-looking statements. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company's oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this Annual Report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company's other public reports, filings and public statements. ITEM 2. PROPERTIES See Item 1. Business - Oil and Gas Operations, Oil and Gas Acreage, Productive Wells and Estimated Net Quantities of Proved Oil and Gas Reserves and Present Value of Estimated Future Net Revenues. The Company also has various operating leases for rental of office space, office equipment, and vehicles. See Note 7 "Commitments and Contingencies" of the Consolidated Financial Statements for the future minimum rental payments. ITEM 3. LEGAL PROCEEDINGS On July 19, 1996, KCS Medallion Resources Inc. filed a lawsuit against the Company and other working interest owners in U.S. District Court - Western District of Louisiana, Lafayette Division, alleging damages of $3.9 million plus certain expenses from a dispute in the interpretation of an operating agreement. Management believes that any settlement of this lawsuit will not be material to the financial position, operation or cash flows of the Company. On November 18, 1996 a class action lawsuit was filed against the Company in the 32nd Judicial District Court, Terrebonne Parish, Louisiana seeking undisclosed damages for personal injury as a result of a gas eruption at Gibson 9 Field, Louisiana. Management believes that any settlement of this lawsuit will not be material to the financial position, operations or cash flow of the Company. There are no other potentially material pending legal proceedings to which the Company or any of its subsidiaries is a party or of which any of their property is the subject. However, due to the nature of its business, certain legal or administrative proceedings arise from time to time in the ordinary course of its business. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS At the Company's Special meeting held on October 9, 1996, the common shareholders of the Company approved the following (as allowed under Canadian regulations, abstentions were not counted). These votes have been adjusted for the one-for-two reverse stock split approved at the Special Meeting and also exclude the votes of any related party in the second and third resolutions.
FOR AGAINST ------------------- ---------------- 1. A Special Resolution, amending the Articles of Continuance of the 7,276,960 2,925 Corporation to consolidate the number of issued and outstanding Common Shares of the Corporation on the basis of one (1) Common Share for each two (2) Common Shares outstanding. 2. A Special Resolution, amending the Articles of Continuance of the 2,965,344 310 Corporation by modifying the conversion provisions attaching to the Convertible First Preferred Shares, Series A (the "Preferred Shares") which will give the Corporation the right to require the holders of the Preferred Shares to convert their Preferred Shares into Common Shares at any time, provided that the conversion rate in effect as of January 1, 1999 will be used for any required conversion prior to such date. 3. An Ordinary Resolution, to authorize the Corporation to issue 7,069,435 2,186 Common Shares at an issue price of Cdn. $7.36 per share in payment of the interest that would be due on the 9 1/2% Convertible Debentures of the Corporation from the conversion date (following shareholder approval of the Ordinary Resolution), to and including April 13, 1997, if the holders of such debentures convert their debentures into Common Shares prior to April 13, 1997.
PART II ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS Information as to the markets in which the Company's Common Stock is traded, the quarterly high and low prices for such stock, the dividends declared with respect to the Common Stock during the last two years, and the approximate number of stockholders of record at February 1, 1997, is set forth under Quarterly Stock Information, appearing on page 47 of the Annual Report. Information as to restrictions on the payment of dividends with respect to the Corporation's Common Stock is set forth in Note 5 to Financial statements, appearing on page 37 of the Annual Report. Such information is incorporated herein by reference. The closing price of the Company's stock on NASDAQ and the TSE on March 17, 1997 was $13.11 and $18.00 respectively. 10 ITEM 6. SELECTED FINANCIAL DATA Selected Financial Data for the Company for each of the last five years are set forth under Financial Highlights, appearing on page 3 of the Annual Report. All such information is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Information as to the Company's financial condition, changes in financial condition and results of operations and other matters is set forth in Management's Discussion and Analysis of Financial Condition and Results of Operations, appearing on pages 21 through 27 of the Annual Report, and is incorporated herein by reference. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Company's consolidated financial statements, accounting policy disclosures, note to financial statements, business segment information and independent auditors' report are presented on pages 28 through 46 of the Annual Report. Selected quarterly financial data are set forth under Unaudited Quarterly Information appearing on page 46 of the Annual Report. All such information is incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY DIRECTORS OF THE COMPANY Information as to the names, ages, positions and offices with Denbury, terms of office, periods of service, business experience during the past five years and certain other directorships held by each director or person nominated to become a director of Denbury is set forth in the Election of Directors segment of the Proxy Statement and is incorporated herein by reference. EXECUTIVE OFFICERS OF THE COMPANY Information concerning the executive officers of Denbury is set forth in the Executive Officers report of the Proxy Statement and is incorporated herein by reference. SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934 and the rules thereunder require the Company's executive officers and directors, and persons who beneficially own more than ten percent (10%) of a registered class of the Company's equity securities, to file reports of ownership and changes in ownership with the Securities and Exchange Commission and exchanges and to furnish the Company with copies. Based solely on its review of the copies of such forms received by it, or written representations from such persons, the Company is not aware of any person who failed to file any reports required by Section 16(a) to be filed for fiscal 1996 except for the late filing of Form 3 by Mr. David Bonderman after he first became a director on May 15, 1996. 11 ITEM 11. EXECUTIVE COMPENSATION Information concerning remuneration received by Denbury's executive officers and directors is presented under the caption "Statement of Executive Compensation" in the Proxy Statement and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information as to the number of shares of Denbury's equity securities beneficially owned as of February 28, 1997, by each of its directors and nominees for director, its five most highly compensated executive officers and its directors and executive officers as a group is presented under the caption "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information on related transactions is presented under the caption "Compensation Committee Interlocks and Insider Participation" and "Interests of Insiders in Material Transactions" in the Proxy Statement and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) FINANCIAL STATEMENTS AND SCHEDULES. Financial statements filed as a part of this report are presented on pages 28 through 46 of the Annual Report and are incorporated herein by reference. The following schedules are filed as part of this report: Schedule I: Condensed Financial Information of the Registrant. EXHIBITS. The following exhibits are filed as a part of this report. EXHIBIT NO. EXHIBIT 3(a) Articles of Continuance of the Company, as amended (incorporated by reference as Exhibits 3(a), 3(b), 3(c), 3(d) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995, Exhibit 4(e) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996 and Exhibit 3(a) of the Pre- effective Amendment No. 2 of the Registrant's Registration Statement on Form S-1 dated October 22, 1996). 3(b) General By-Law No. 1: A By-Law Relating Generally to the Conduct of the Affairs of the Company, as amended (incorporated by reference as Exhibit 3(e) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995 and Exhibit 4(d) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 12 EXHIBIT NO. EXHIBIT 4(a) "Common Shares" section of Schedule "A" to Articles of Amendment of Newscope Resources Limited dated December 13, 1990, exhibited in full at 3(a) (incorporated by reference as Exhibit 4(a) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(b) Section 1.05 of General By-Law No. 1, exhibited in full at 3(b) (incorporated by reference as Exhibit 4(b) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 4(c) Pages 8-14 of General By-Law No. 1, exhibited in full at 3(b) (incorporated by reference as Exhibit 4(c) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(a)Shelf Registration Agreement dated April 24, 1995, by and among Newscope Resources Ltd. and holders of Special Warrants (incorporated by reference as Exhibit 10(a) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(b)Credit Agreement between Denbury Management Inc., Borrower, Denbury Resources Inc., Guarantor, Denbury Holdings, Ltd., Guarantor, and NationsBank of Texas N.A. as agent dated May 31, 1996 (incorporated by reference as Exhibit 10(b) of the Registrant's Post-effective Amendment No. 2 to Form F-1 on Form S-1 dated June 25, 1996). 10(c)Common Share Purchase Warrant representing right of Internationale Nederlanden (U.S.) Capital Corporation to purchase 150,000 Common Shares of Newscope Resources Ltd. (incorporated by reference as Exhibit 10(c) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(d)Registration Rights Agreement dated May 5, 1995, between Internationale Nederlanden (U.S.) Capital Corporation and Newscope Resources Ltd. (incorporated by reference as Exhibit 10(d) of the Registrant's Registration Statement on Form F-1 dated August 25, 1995). 10(e)Denbury Resources Inc. Stock Option Plan (incorporated by reference as Exhibit 4(f) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 10(f)Denbury Resources Inc. Stock Purchase Plan (incorporated by reference as Exhibit 4(g) of the Registrant's Registration Statement on Form S-8 dated February 2, 1996). 10(g)Form of indemnification agreement between Newscope Resources Ltd. and its officers and directors (incorporated by reference as Exhibit 10(h) of the Registrant's Form 10-K for the year ended December 31, 1995). 10(h)Securities Purchase Agreement and exhibits between Newscope Resources Ltd. and TPG Partners, L.P. as of November 13, 1995 (incorporated by reference as Exhibit 10(i) of the Registrant's Form 10-K for the year ended December 31, 1995). 13 EXHIBIT NO. EXHIBIT 10(i)First Amendment to the November 13, 1995 Securities Purchase Agreement between Newscope Resources Ltd. and TPG Partners, L.P. as of December 21, 1995 (incorporated by reference as Exhibit 10(j) of the Registrant's Form 10-K for the year ended December 31, 1995). 10(j)Stock Purchase Agreement between TPG Partners, L.P. and Denbury Resources Inc. dated as of October 2, 1996, (incorporated by reference as Exhibit 10(k) of the Post-effective Amendment No. 2 of the Registrant's Registration Statement on Form S-1 dated October 22, 1996 11* Statement re-computation of per share earnings. 13* Annual Report to the Security Holders. 21* List of Subsidiaries of Denbury Resources Inc. 23* Consent of Deloitte & Touche. 27* Financial Data Schedule. * Filed herewith. (b) 8-K'S FILED DURING THE FOURTH QUARTER OF 1996. None 14 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. DENBURY RESOURCES INC. Company March 19, 1997 /s/ Phil Rykhoek --------------------------- Phil Rykhoek Chief Financial Officer and Secretary Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated. March 19, 1997 /s/ Ronald G. Greene -------------------- Ronald G. Greene Chairman of the Board and Director March 19, 1997 /s/ Gareth Roberts ------------------ Gareth Roberts Director, President and Chief Executive Officer (Principal Executive Officer) March 19, 1997 /s/ Phil Rykhoek ---------------- Phil Rykhoek Chief Financial Officer and Secretary (Principal Accounting and Financial Officer) March 19, 1997 /s/ David M. Stanton -------------------- David M. Stanton Director March 19, 1997 /s/ Wieland F. Wettstein ------------------------ Wieland F. Wettstein Director 15 INDEPENDENT AUDITORS' REPORT To the Shareholders of Denbury Resources Inc. We have audited the financial statements of Denbury Resources Inc. as of December 31, 1996 and 1995, and for each of the three years in the period ended December 31, 1996, and have issued our report thereon dated February 21, 1997, such financial statements and report are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of Denbury Resources Inc., listed in Item 14. This financial statement schedule is the responsibility of the Corporation's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein. Deloitte & Touche Chartered Accountants Calgary, Alberta February 21, 1997 1 SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. UNCONSOLIDATED BALANCE SHEETS (Amounts in thousands of U.S. dollars)
December 31, ------------------------------------ 1996 1995 ------------- ------------- Assets CURRENT ASSETS Cash and cash equivalents $ 274 $ 8 TRADE AND OTHER RECEIVABLES 6 7 ------------- ------------- TOTAL CURRENT ASSETS 280 15 ------------- ------------- INVESTMENT IN SUBSIDIARIES (EQUITY METHOD) 140,763 70,130 LOAN RECEIVABLE FROM SUBSIDIARY 1,558 1,563 OTHER ASSETS 2 28 ------------- ------------- Total assets $ 142,603 $ 71,736 ============= ============= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 99 $ 9 LONG-TERM DEBT - 3,226 ------------- ------------- 99 3,235 ------------- ------------- Convertible First Preferred Shares, Series A 1,500,000 shares authorized; issued and outstanding at December 31, 1995 - 15,000 ------------- ------------- SHAREHOLDERS' EQUITY Common shares, no par value unlimited shares authorized; outstanding - 20,055,757 shares at December 31, 1996 and 11,428,809 shares at December 31, 1995 130,323 50,064 RETAINED EARNINGS 12,181 3,437 ------------- ------------- TOTAL SHAREHOLDERS' EQUITY 142,504 53,501 ------------- ------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 142,603 $ 71,736 ============= =============
(SEE NOTES TO CONDENSED FINANCIAL STATEMENTS) 2 SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. UNCONSOLIDATED STATEMENTS OF INCOME (Amounts in thousands except per share amounts) (U.S. dollars)
Year Ended December 31, --------------------------------------------------- 1996 1995 1994 ----------- ----------- ----------- REVENUES Interest income and other $ 179 $ 460 $ 1 ----------- ----------- ----------- EXPENSES General and administrative 161 178 149 Interest 304 282 76 Imputed preferred dividends 1,281 - - Depletion and depreciation - - 2 ----------- ----------- ----------- Total expenses 1,746 460 227 ----------- ----------- ----------- Loss before the following: (1,567) - (226) Equity in net earnings of subsidiaries 10,311 714 1,389 ----------- ----------- ----------- Income before income taxes 8,744 714 1,163 Provision for federal income taxes - - - ----------- ----------- ----------- NET INCOME $ 8,744 $ 714 $ 1,163 =========== =========== =========== NET INCOME PER COMMON SHARE Primary $ 0.67 $ 0.10 $ 0.19 Fully diluted 0.62 0.10 0.19 Average number of common shares outstanding 13,104 6,870 6,240 =========== =========== ===========
(See Notes to Condensed Financial Statements) 3 SCHEDULE 1 - CONDENSED FINANCIAL INFORMATION OF REGISTRANT DENBURY RESOURCES INC. UNCONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in thousands of U.S. dollars)
Year Ended December 31, ------------------------------------------ 1996 1995 1994 ----------- ----------- ------------ CASH FLOW FROM OPERATING ACTIVITIES: Net income $ 8,744 $ 714 $ 1,163 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization - - 2 Imputed preferred dividend 1,281 - - Other 114 17 9 Equity in net earnings of subsidiaries (10,311) (714) (1,389) ----------- ----------- ------------ (172) 17 (215) Changes in working capital items relating to operations: Trade and other receivables - (4) 8 Accounts payable and accrued liabilities 90 (12) (77) ----------- ----------- ------------ NET CASH FLOW PROVIDED BY (USED BY) OPERATIONS (82) 1 (284) ----------- ----------- ------------ CASH FLOW FROM INVESTING ACTIVITIES: Investments in subsidiaries (60,316) (43,569) (1,518) Net purchases of other assets - 7 (15) ----------- ----------- ------------ NET CASH USED FOR INVESTING ACTIVITIES (60,316) (43,562) (1,533) ----------- ----------- ------------ CASH FLOW FROM FINANCING ACTIVITIES: Issuance of subordinated debt - 1,772 1,451 Issuance of common stock 60,664 26,825 367 Issuance of preferred stock - 15,000 - Costs of debt financing - (35) - ----------- ----------- ------------ NET CASH PROVIDED BY FINANCING ACTIVITIES 60,664 43,562 1,818 ----------- ----------- ------------ NET INCREASE IN CASH AND CASH EQUIVALENTS 266 1 1 Cash and cash equivalents at beginning of year 8 7 6 ----------- ----------- ------------ CASH AND CASH EQUIVALENTS AT END OF YEAR $ 274 $ 8 $ 7 =========== =========== ============ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for interest $ 277 $ 282 $ 76
(See Notes to Condensed Financial Statements) 4 DENBURY RESOURCES INC. SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRATION NOTES TO FINANCIAL STATEMENTS NOTE 1. ACCOUNTING POLICIES Consolidation - The financial statements of Denbury Resources Inc. have been prepared in accordance with Canadian generally accepted accounting principles and reflect the investment in subsidiaries using the equity method. Income Taxes - No provision for income taxes has been made in the Statement of Income because the Company has losses for Canadian tax purposes. NOTE 2. CONSOLIDATED FINANCIAL STATEMENTS Reference is made to the Consolidated Financial Statements and related notes of Denbury Resources Inc. and Subsidiaries for additional information. NOTE 3. DEBT AND GUARANTEES Information on the long-term debt of Denbury Resources Inc. is disclosed in Note 3 to the Consolidated Financial Statements. Denbury Resources Inc. has guaranteed the subsidiaries' bank credit line. NOTE 4. DIVIDENDS RECEIVED Subsidiaries' of Denbury Resources Inc. do not make formal cash dividend declarations and distributions to the parent and are currently restricted from doing so under the subsidiaries bank loan agreement. 5 EX-11 2 EXHIBIT 11 EXHIBIT 11 DENBURY RESOURCES INC. COMPUTATION OF EARNINGS PER COMMON SHARE
Year Ended December 31, ---------------------------------------- 1996 1995 1994 ---------- ---------- --------- CANADIAN GAAP (Amounts in thousands except per share amounts) PRIMARY EPS: Weighted average shares outstanding 13,104 6,870 6,240 ---------- ---------- --------- Net income $ 8,744 $ 714 $ 1,163 ---------- ---------- --------- PRIMARY EARNINGS PER COMMON SHARE $ 0.67 $ 0.10 $ 0.19 ========== ========== ========= FULLY DILUTED EPS: Weighted average shares outstanding 13,104 6,870 6,240 Assumed conversions: Convertible debentures 391 (a) (a) Warrants 750 (a) (a) Stock options 1,053 (a) (a) Convertible preferred (a) (b) (b) ---------- ---------- --------- ADJUSTED SHARES OUTSTANDING 15,298 6,870 6,240 ---------- ---------- --------- Net income $ 8,744 $ 714 $ 1,163 Adjustments: Interest on subordinated debentures 126 (a) (a) Interest on warrant proceeds 245 (a) (a) Interest on option proceeds 365 (a) (a) Imputed preferred dividend (a) (b) (b) ---------- ---------- --------- ADJUSTED NET INCOME $ 9,480 $ 714 $ 1,163 ---------- ---------- --------- FULLY DILUTED EARNINGS PER COMMON SHARE $ 0.62 $ 0.10 $ 0.19 ========== ========== ========= (a) Anti-dilutive or immaterial (b) Not applicable for this period
1 EXHIBIT 11 DENBURY RESOURCES INC. COMPUTATION OF EARNINGS PER COMMON SHARE
Year Ended December 31, ------------------------------------- 1996 1995 1994 -------- --------- --------- U.S. GAAP (Amounts in thousands except per share amounts) PRIMARY EPS: Weighted average shares outstanding 13,104 6,870 6,240 Net adjustments after assumed repurchases of stock with proceeds from: Warrants 280 (a) (a) Stock options 221 (a) (a) -------- --------- --------- ADJUSTED SHARES OUTSTANDING 13,605 6,870 6,240 -------- --------- --------- NET INCOME $ 8,744 $ 714 $ 1,163 -------- --------- --------- PRIMARY EARNINGS PER COMMON SHARE $ 0.64 $ 0.10 $ 0.19 ========= ========= ========= FULLY DILUTED EPS: Weighted average shares outstanding 13,104 6,870 6,240 Assumed Conversions: Convertible debentures 391 (a) (a) Net adjustments after assumed repurchases of stock with proceeds from: Warrants 402 (a) (a) Stock options 397 (a) (a) Convertible preferred (a) (b) (b) --------- -------- --------- ADJUSTED SHARES OUTSTANDING 14,294 6,870 6,240 --------- -------- --------- Net income $ 8,744 $ 714 $ 1,163 Adjustments: Interest on subordinated debentures 220 (a) (a) Imputed preferred dividend (a) (b) (b) --------- -------- --------- ADJUSTED NET INCOME $ 8,935 $ 714 $ 1,163 --------- -------- --------- FULLY DILUTED EARNINGS PER COMMON SHARE $ 0.63 $ 0.10 $ 0.19 ========= ========= ========= (a) Anti-dilutive or immaterial (b) Not applicable for this period
2 EX-13 3 EXHIBIT 13 EXHIBIT 13 PAGE 3 AND PAGES 8 THROUGH 47, INCLUSIVE, OF THE COMPANY'S ANNUAL REPORT TO SHAREHOLDERS FOR THE YEAR ENDED DECEMBER 31, 1996, BUT EXCLUDING PHOTOGRAPHS AND ILLUSTRATIONS SET FORTH ON THESE PAGES, NONE OF WHICH SUPPLEMENTS THE TEXT AND WHICH ARE NOT OTHERWISE REQUIRED TO BE DISCLOSED IN THIS ANNUAL REPORT ON FORM 10-K. 1 FINANCIAL HIGHLIGHTS
YEAR ENDED DECEMBER 31, AVERAGE ANNUAL GROWTH (2) -------------------------------------------------------- ----------- AMOUNTS IN THOUSANDS OF U.S. DOLLARS UNLESS NOTE 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------------------------------- PRODUCTION (DAILY) Oil (Bbls) 4,099 1,995 1,340 858 221 108% Gas (Mcf) 24,406 13,271 9,113 2,013 1,288 109% BOE (6:1) 8,167 4,207 2,858 1,193 436 108% REVENUE (NET OF ROYALTIES) Oil sales 28,475 10,852 6,767 4,356 1,244 119% Gas sales 24,405 9,180 5,925 1,512 668 146% Total 52,880 20,032 12,692 5,868 1,912 129% UNIT SALES PRICE Oil (per Bbl) 18.98 14.90 13.84 13.91 15.36 5% Gas (per Mcf) 2.73 1.90 1.78 2.06 1.42 18% CASH FLOW FROM OPERATIONS (1) 34,140 9,394 6,185 3,030 354 213% NET INCOME 8,744 714 1,163 1,735 (335) 126% AVERAGE COMMON SHARES OUTSTANDING 13,104 6,870 6,240 4,990 2,949 45% PER SHARE: PER SHARE: Cash flow from operations: (1) Primary 2.51 1.37 0.99 0.61 0.12 114% Fully diluted 2.07 1.37 0.99 0.61 0.12 106% Net income: Primary 0.67 0.10 0.19 0.35 (0.11) 83% Fully diluted 0.62 0.10 0.19 0.35 (0.11) 82% OIL AND GAS CAPITAL INVESTMENTS 86,857 28,524 16,903 29,855 6,189 94% TOTAL ASSETS 166,505 77,641 48,964 35,978 8,225 112% LONG-TERM LIABILITIES 7,481 5,077 17,768 6,633 205 146% SHAREHOLDERS' EQUITY AND PREFERRED STOCK 142,504 68,501 25,962 24,431 7,548 108% PROVEN RESERVES Oil (MBbls) 15,052 6,292 4,230 3,583 1,243 87% Gas (MMcf) 74,102 48,116 42,046 13,029 2,895 125% BOE (6:1) 27,403 14,312 11,237 5,755 1,725 100% Discounted future cash flow - 10% 316,098 96,965 52,691 28,638 8,512 147% PER BOE DATA (6:1) Revenue 17.69 13.05 12.17 13.47 11.99 10% Production expenses (4.51) (4.42) (4.13) (4.75) (3.97) 3% - ------------------------------------------------------------------------------------------------------------------- Production netback 13.18 8.63 8.04 8.72 8.02 13% General and administrative expenses (1.50) (1.25) (1.12) (1.80) (5.99) (29)% Interest expenses (0.26) (1.26) (0.99) 0.04 0.19 8% - ------------------------------------------------------------------------------------------------------------------- CASH FLOW (1) 11.42 6.12 5.93 6.96 2.22 51% - ------------------------------------------------------------------------------------------------------------------- (1) Exclusive of the net change in non-cash working capital balances. (2) Computed using 1992 as a base year.
---------------------------------------------------------------------- Reporting Format During 1995, the Company began reporting its financial results in a format more consistent with U.S. presentations. Unless otherwise noted, the disclosures in this report have (i) dollar amounts presented in U.S. dollars, (ii) production volumes expressed on a net revenue interest basis, (iii) gas volumes are converted to equivalent barrels at 6:1. 3 Selected Operating Data OIL AND GAS RESERVES The reserves at December 31, 1996 and 1995 were estimated by Netherland, Sewell & Associates, Inc., an independent Dallas-based engineering firm. The reserves were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission ("SEC"), based on the prices received on a field-by-field basis as of December 31 of each year. The reserves do not include any value for probable or possible reserves which may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the net revenue interest (after royalties) of the Company. The 1994 reserves were prepared by the Scotia Group.
AS OF DECEMBER 31, ------------------------------------------- 1996 1995 1994 ------------- ------------ ------------ ESTIMATED PROVED RESERVES: Oil (MBbls)................................................ 15,052 6,292 4,230 Natural Gas (MMcf)......................................... 74,102 48,116 42,047 Oil Equivalent (MBOE)...................................... 27,403 14,311 11,238 PERCENTAGE OF MBOE: Proved producing........................................... 45% 38% 44% Proved non-producing....................................... 39% 40% 42% Proved undeveloped......................................... 16% 22% 14% REPRESENTATIVE OIL AND GAS PRICES: (1) West Texas Intermediate $ 23.39 $ 18.00 $ 15.48 NYMEX Henry Hub 3.90 2.24 1.66 PRESENT VALUES: Discounted estimated future net cash flow before income taxes (PV10 Value) (thousands) (2)..............$ 316,098 (3)$ 96,965 $ 52,691 Standardized measure of discounted estimated future net cash flow after net income taxes (thousands)..............$ 241,872 $ 81,164 $ 46,928 --------------- (1) The oil prices as of each respective year-end were based on West Texas Intermediate "WTI"prices per barrel and NYMEX Henry Hub prices per MMBtu ,with these representative prices adjusted by field to arrive at the appropriate corporate net price. (2) Determined based on year-end unescalated prices and costs in accordance with the guidelines of the SEC, discounted at 10% per annum. (3) Since December 31, 1996, the oil and natural gas prices have significantly declined which reduce not only the PV10 value, but may also reduce the reserve quantities. For comparative purposes, the Company prepared a December 31, 1996 reserve report using a WTI price of $21.00 per Bbl and a NYMEX price of $2.40 per MMBtu, with these prices also adjusted by field. The PV10 value in this report was $213.7 million with 27.0 MMBOE of proved reserves.
CAPITAL EXPENDITURES Denbury's commitment to future growth is best demonstrated by its reinvestment levels. The major components of the Company's capital expenditure programs over the last three years are as follows:
(Amounts in Thousands) Year Ended December 31, ---------------------------------------------- 1996 1995 1994 ------------- ------------- ------------- Property acquisition.................................... $ 48,856 $ 17,198 $ 6,736 Exploration............................................. 4,592 1,687 1,796 Development............................................. 33,409 9,639 8,371 ------------- ------------- ------------- TOTAL CAPITAL EXPENDITURES $ 86,857 $ 28,524 $ 16,903 ============= ============= =============
8 FINDING COST Finding costs are one of the primary critical factors in determining a company's profitability. During 1996, the Company spent almost 56% of its capital expenditures on acquisitions. This helps provide the base for future growth but often carries a higher unit cost per barrel until after the Company has had an opportunity to better evaluate the properties and determine their ultimate potential. In addition, one must also look at the type of reserves acquired as the cost per BOE will vary depending on the netbacks, timing of cash flow, etc. In the finding cost calculation, all oil and gas expenditures incurred, including capital expenditures which will benefit future years such as seismic surveys, prospect costs and undeveloped properties, have been included in the calculations. The forecasted future development costs, as outlined in the independent engineer's reserve forecast, have not been included in the calculation. The reserves are obtained from the unescalated SEC price case using the Company's net revenue interest, plus applicable historical production. BOE equivalents are calculated using six Mcf per one barrel of oil.
THREE YEAR INCEPTION AVERAGE TO 1996 1994-1996 DATE - ---------------------------------------------------------------------------------------------------------- Total capitalized costs (millions) $ 86.9 $ 132.4 $ 166.1 Proved reserve additions and production (MMBOE) 16.1 27.2 33.5 - ---------------------------------------------------------------------------------------------------------- AVERAGE FINDING COST PER BOE (6:1) $ 5.40 $ 4.87 $ 4.96 - ----------------------------------------------------------------------------------------------------------
FIELD SUMMARIES
1996 PROVED RESERVES AS OF DECEMBER 31, 1996 AVERAGE PRODUCTION (1) -------------------------------------------- ----------------------- AVERAGE NATURAL NATURAL GROSS NET OIL GAS PV10 VALUE PV10 VALUE OIL GAS PRODUCTIVE REVENUE (MBBLS) (MMCF) (000'S) % OF TOTAL (BBLS/D) (MCF/D) WELLS (2) INTEREST(2) ------------------------------------------------------------------------------------------ ---------- LOUISIANA Lirette.......... 255 26,854 $ 70,285 22.2% 164 9,188 16 61.0% Gibson........... 285 7,591 23,449 7.4% 180 4,080 2 53.8% Lake Chicot...... 253 6,761 21,272 6.7% 20 5 6 37.6% South Chauvin.... 244 8,711 20,798 6.6% 10 381 4 72.9% Bayou Rambio..... 45 6,022 15,559 4.9% 20 1,548 1 72.1% Lapeyrouse....... 128 2,593 8,657 2.7% 3 68 3 61.8% Other Louisiana.. 1,435 10,807 41,888 13.4% 615 6,202 78 42.5% -------- ---------- ---------- ---------- --------- --------- ---------- ---------- Total Louisiana 2,645 69,339 201,908 63.9% 1,012 21,472 110 46.6% -------- ---------- ---------- ---------- --------- --------- ---------- ---------- MISSISSIPPI Eucutta.......... 4,131 - 33,472 10.6% 776 - 34 74.7% Davis............ 2,670 - 23,979 7.6% 764 - 24 72.3% Quitman.......... 2,289 - 19,498 6.2% 224 - 15 77.6% Dexter........... - 3,503 7,438 2.4% 1 2,027 7 51.7% West Yellow Creek 1,054 - 7,381 2.3% 268 - 7 78.2% S. Thompson Creek 379 - 4,493 1.4% 257 - 4 80.2% Other Mississippi 1,754 696 14,357 4.5% 721 376 79 40.8% -------- ---------- ---------- ---------- --------- --------- ---------- ---------- Total Mississippi 12,277 4,199 110,618 35.0% 3,011 2,403 170 58.2% -------- ---------- ---------- ---------- --------- --------- ---------- ---------- OTHER............... 130 564 3,572 1.1% 76 531 16 36.7% -------- ---------- ---------- ---------- --------- --------- ---------- ---------- COMPANY TOTAL 15,052 74,102 $ 316,098 100.0% 4,099 24,406 296 52.7% ======== ========== ========== ========== ========= ========= ========== ========== (1) Average production during the period from January 1, 1996 through December 31, 1996. Certain properties, including those purchased in the Hess and Ottawa Acquisitions, were acquired during 1996. This table only includes production during the periods when such properties were owned by the Company. (2) Includes only productive wells in which the Company had a working interest as of December 31, 1996.
9 ACQUISITIONS OF OIL AND NATURAL GAS PROPERTIES The Company regularly seeks to acquire properties that complement its operations, that provide exploitation, exploration and development opportunities and that have cost reduction potential. The Company has purchased the majority of its current producing wells and has increased production by a variety of techniques, including development drilling, increasing fluid withdrawal and reworking existing wells. These acquisitions have also balanced the Company's reserve mix between oil and natural gas, increased the scale of its operations in the onshore Gulf Coast area and provided the Company with a significant base of operations within its area of geographic focus. Since 1993, aggregate expenditures to acquire producing properties were approximately $91.9 million. During 1996, the Company spent approximately $45 million on its two largest acquisitions. These two acquisitions are discussed below. Hess Acquisition The largest acquisition by the Company to date, which occurred during the first half of 1996, was the acquisition of producing oil and natural gas properties in Mississippi, Louisiana, and Alabama for approximately $37.2 million from Amerada Hess (the "Hess Acquisition"). The average daily production from the properties included in the Hess Acquisition during May and June 1996, the first two months of ownership, was approximately 2,945 BOE/d. By December 1996, the Company had increased the production on these properties to approximately 3,400 BOE/d. In the Company's December 31, 1996 independent reserve report (the "December Report"), the properties in this acquisition had estimated net proved reserves of approximately 9.5 MMBOE with a discounted present value using a 10% discount rate ("PV10 Value") of $96.1 million. This compares to approximately 5.9 MMBOE and a $43.1 million PV10 Value as of July 1, 1996 in the Company's mid-year independent reserve report (the "July Report"). Prices were calculated in the December Report based on a West Texas Intermediate ("WTI") price of $23.39 per Bbl and a NYMEX Henry Hub price of $3.90 per MMBTU, with these representative prices adjusted by field to arrive at the appropriate corporate net price, as compared to oil and gas prices of $20.00 and $2.65 respectively in the July Report. For comparative purposes the Company also prepared a December 31, 1996 report using a WTI price of $21.00 per Bbl and NYMEX price of $2.40 per MMBTU, with these prices also adjusted by field (the "Modified Report"). The PV10 Value in the Modified Report was $72.0 million for the properties acquired in the Hess Acquisition. Three fields, out of a total of 60 fields, comprise over 75% of the total Hess Acquisition PV10 Value as of December 31, 1996. The two largest fields in Mississippi, Eucutta and Quitman Fields, make up approximately 55% of the total PV10 Value. Both fields are in the same vicinity as the Company's existing Mississippi core properties, with the Eucutta Field located in Wayne County, Mississippi between the Company's Sandersville and West Yellow Creek existing production. The Quitman Field is located in Clarke County, Mississippi, adjacent to the Company's Davis and Frances Creek existing production. The largest field in Louisiana is the Lake Chicot Field, which comprises approximately 22% of the total PV10 Value. Lake Chicot is in St. Martin Parish, just Northwest of Terrebonne Parish where the majority of the Company's existing Louisiana production is located. Ottawa and other 1996 Acquisitions In addition to the Hess Acquisition, the Company completed other acquisitions during 1996 totaling $11.2 million. The largest of these was an acquisition of additional working interests in five Mississippi oil and natural gas properties in which the Company already owned an interest, plus certain overriding royalty interests in other areas, which were acquired during April 1996 for approximately $7.5 million (the "Ottawa Acquisition"). The average daily production from the Ottawa Acquisition during April, May and June 1996, 10 the first three months of ownership, was approximately 600 BOE/d. By December, 1996, the Company had increased the net production on these properties to approximately 650 BOE/d. In addition to the Ottawa Acquisition, the Company spent an additional $3.7 million on nine other acquisitions, primarily in Louisiana. The properties in these nine acquisitions were producing approximately 360 BOE/d as of December 1996. The Company's estimated net proved reserves in the December Report for all of these other acquisitions, including the Ottawa Acquisition, totaled approximately 4.0 MMBOE, with a PV10 Value of $47.4 million. This compares to approximately 3.3 MMBOE and a $24.1 million PV10 Value in the July Report. The PV10 Value in the Modified Report was $29.4 million for these same properties. Denbury operates in two core areas, Louisiana and Mississippi. The Company operates 62 wells in Louisiana from an office in Houma and 119 wells in Mississippi from an office in Laurel. Twelve of the Company's largest oil and natural gas fields as outlined on page 9 constitute approximately 80% of its total reserves on both a BOE and PV10 Value basis Within these 12 fields, Denbury owns an average 84% working interest and operates 82% of the wells, which comprise 65% of the Company's PV10 Value. This concentration of value in a relatively small number of fields allows the Company to benefit substantially from any operating cost reductions or production enhancements and allows the Company to effectively manage the properties from its two field offices. These two core areas are similar in that the major trapping mechanisms for oil and natural gas accumulations are structural features usually related to deep-seated salt or shale movement. Both areas typically feature mostly multiple sandstone reservoirs with strong water-drive characteristics. However, the two areas differ significantly in drilling costs, risks and the size of potential reserves. In Mississippi, the producing zones are generally shallower than in Louisiana and therefore drilling and workover costs are lower. However, the geological complexity of southern Louisiana, which is more expensive to exploit, creates the potential for larger discoveries, particularly of natural gas. The Company's production in Louisiana is predominately natural gas, while Mississippi is predominately oil. (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) 11 (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) 12 Operations in Southern Louisiana The Company's southern Louisiana producing fields are typically large structural features containing multiple sandstone reservoirs. Current production depths range from 7,000 feet to 16,000 feet with potential throughout the areas for even deeper production. The region produces predominantly natural gas, with most reservoirs producing with a water-drive mechanism. The majority of the Company's southern Louisiana fields lie in the Houma embayment area of Terrebonne and LaFourche Parishes. The area is characterized by complex geological structures which have produced prolific reserves, typical of the lower Gulf Coast geosyncline. Given the swampy conditions of southern Louisiana, 3-D seismic has only recently become feasible for this area as improvements in field recording techniques have made the process more economical. 3-D seismic has become a valuable tool in exploration and development throughout the onshore Gulf Coast and has been pivotal in discovering significant reserves. The Company believes that the first generation of 3-D data acquired in these swampy areas has the potential to identify significant exploration prospects, particularly in the deeper geopressured sections below 12,000 feet. Lirette The Lirette structure is a large salt-cored anticline located about 10 miles south of Houma, Louisiana, which has produced over one Tcf of natural gas from multiple reservoirs. The field is located in six to ten feet of inland water and produces from depths of 8,000 feet to 16,000 feet. The field was discovered in 1937, but in 1993, when the Company first acquired a 23% working interest in the field, gross production had declined to less than 3 MMcf/d. By January 1995, following a series of workovers of existing wells, gross production had grown to approximately 13.2 MMcf/d and 360 Bbls/d (6.5 MMcf/d and 150 Bbls/d net). Additional interests were acquired in early 1995 to increase the Company's ownership to its current average 78% working interest. As a result of two workovers and two wells drilled during 1996, net production had increased during December 1996 to 11.0 MMcf/d and 167 Bbls/d from 13 wells. During the latter half of 1996, the Lirette Field was covered by a 3-D survey which is currently being processed and evaluated. It is anticipated that drilling projects created out of this seismic work will probably be drilled in late 1997 or 1998. Gibson/Humphreys In late 1994, Denbury acquired minor working interests in five wells in the Gibson and Humphreys Fields located in Terrebonne Parish, 20 miles northwest of the Lirette Field, in the northern part of the Houma embayment. The Gibson Field, discovered in 1937, has produced over 813 Bcf and 14 MMBbls while the Humphreys Field, discovered in 1956, has produced 527 Bcf and 6 MMBbls. During 1995, the Company acquired and processed 38 square miles of 3-D seismic data covering these fields and in November 1995 acquired a majority working interest in these fields. By December 1995, Denbury's acreage position had grown to 3,165 net acres with interests in six active wells and eight inactive wells. During December 1996, net production in these two fields averaged approximately 5.1 MMcf/d and 90 Bbls/d. Two additional wells are currently planned in this area during 1997. South Chauvin In February 1996, Denbury purchased interests in two producing wells and four non-producing wells in South Chauvin Field located in the Houma embayment area, about four miles south of Houma and six miles northwest of Lirette Field. Of the three currently producing wells at Chauvin, Denbury owns an average 95% working interest. During December 1996, 13 (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) these three wells produced at an average net rate of 1.0 MMcf/d. In late 1996, the Company acquired 13.7 square miles of 3-D seismic data covering the field and is currently evaluating the data. Assuming the seismic interpretation is favorable, the Company plans to drill two wells in 1997. Bayou Rambio Production at the Bayou Rambio Field was established in 1955 and has exceeded 150 Bcf and 920 MBbls to date. Denbury operates one producing well in the field, the Kelly #2 which is located in Terrebonne Parish about 15 miles west of Lirette Field. During December 1996, the Kelly #2 produced at an average net rate of approximately 0.7 MMcf/d and 9 Bbls/d. The Company is currently evaluating 15 square miles of 3-D seismic data covering this area. Based upon this evaluation, two development locations are tentatively scheduled to be drilled during 1997. This field has historically produced from 25 different pay zones. Lapeyrouse The Lapeyrouse Field is a large structural feature which has produced over 2 Tcf and 10 MMBbls since its discovery in 1941. Denbury currently operates one producing well and one shut-in well and has a small interest in one other producing well in the Lapeyrouse field. Net production from this area was relatively minor during December 1996, averaging 0.1 MMcf/d and 2 Bbls/d. However, this area is part of the Lirette 3-D joint venture and also will be covered by the 147 square mile 3-D survey conducted in late 1996. The Company believes considerable potential exists in the section below 15,000 feet which has produced 8 Bcf from one well in the field. The Company is planning two workovers and two additional wells in 1997, pending the evaluation of the 3-D seismic data. Bayou Des Allemands The Company has a 50% working interest in 17 operated producing wells in the Bayou Des 14 (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) Allemands Field, located in the LaFourche and St. Charles Parishes. This field was acquired as part of the Hess Acquisition. During December 1996, net production from this field averaged 0.1 MMcf/d and 207 Bbls/d. Production in this field is from discrete sand intervals located from 3,700 feet to 11,500 feet in depth. Over 30 behind pipe sands have been identified for future completion as the present zones deplete. Additional potential may exist in updip locations in producing fault blocks, in untested fault blocks and in deeper horizons. A 3-D seismic survey is planned during 1997 to help identify any upside potential. (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) Lake Chicot The Company also acquired Lake Chicot Field in St. Martin Parish, Louisiana as part of the Hess Acquisition and has a 50% working interest in 12 wells. Only three wells are currently producing, although the Company is in the process of returning another nine wells to production. The Company plans to drill four wells in this area in 1997 based upon the interpretation of an existing 3-D seismic grid over the field. Other Louisiana During 1996, Denbury drilled a horizontal well in the Breton Sound Blocks 12 and 13 located in Louisiana State water approximately 70 miles southeast of New Orleans. During December, 1996 net production from this well averaged 0.3 MMcf/d and 145 Bbls/d. In addition the company operates wells at Bully Camp, Delarge, N. Bougere, Atchafalaya Bay, Garden City, Grand Lake and Live Oak Fields. Southern Louisiana 3-D Acquisitions During 1995, the Company acquired approximately 46 square miles of 3-D seismic data over five of its existing fields in southern Louisiana consisting of Bayou Rambio, DeLarge, North Deep Lake, Gibson and Humphreys. During 1996, the Company entered into a joint venture agreement with two industry partners to acquire approximately 147 square miles of 3-D seismic data in the Terrebonne Parish area, which includes three of the Company's existing fields, Lirette, Lapeyrouse and North Lapeyrouse. The Company's existing productive zones are excluded from the joint venture. Denbury will own a one-third interest in any new prospects discovered through this joint venture, which currently owns rights to over 35,000 acres within the survey area. The Company will be responsible for one-third of the cost of both the 3-D seismic survey and any wells drilled. The Company anticipates that the 3-D seismic survey should be completed and the data analyzed by the fall of 1997. 15 (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) 16 Operations in Mississippi In Mississippi, most of the Company's production is oil, produced largely from depths of less than 10,000 feet. Fields in this region are characterized by relatively small geographic areas which generate prolific production from multiple pay sands. The Company's Mississippi production is usually associated with large amounts of saltwater, which must be disposed of in saltwater disposal wells, and almost all wells require pumping. These factors increase the operating costs on a per barrel basis as compared to Louisiana. The Company places considerable emphasis on reducing these costs in order to maximize the cash flow from this area. Eucutta The Eucutta Field is located about 18 miles east of Laurel, Mississippi. Since its discovery in 1943, this field has produced 63 MMBbls and 4.7 Bcf. Denbury acquired the majority of its interests in this field as part of the recent Hess Acquisition and currently operates 31 producing oil wells and 16 saltwater injection wells. (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) The field is divided into a shallow Eutaw sand unit in which the Company has a 76% working interest and the deeper Tuscaloosa sand zones in which the Company has a 100% working interest. The Eucutta Field traps oil in multiple sandstones in a highly faulted anticline. At present, seven different sands are productive at depths between 5,000 feet and 11,000 feet. Most of the wells produce oil with large amounts of saltwater, which require pumping. During December 1996, net production from this field averaged 1,328 Bbls/d. The Company plans a capital expenditure program at Eucutta Field which will include upgrading production facilities, drilling wells and a 3-D seismic evaluation. The Company believes that through a combination of these investments, production can be increased and operating costs reduced. Eight wells are planned to be drilled in 1997. Consideration is being given to acquiring a 3-D seismic survey over the field and, if pursued, most likely would occur in 1997. Davis/Frances Creek The Davis Field and nearby Frances Creek Field are located 42 miles northeast of Laurel in the northern part of the Mississippi salt basin. Denbury operates 19 producing wells within the area and owns minor non-operated interests in eight other wells. The net average production from these wells during December 1996 was approximately 1,254 Bbls/d. Davis is a compact anticline that has produced over 21 MMBbls since its discovery by Conoco in 1969. Over 30 sands have produced oil between the intervals of 5,000 feet and 8,000 feet. Both the Davis and Frances Creek Fields are relatively mature fields and produce large amounts of saltwater. During December 1996, these fields produced an average of approximately 50,000 barrels of saltwater per day, all of which were re-injected into the ground. The Company places considerable emphasis on controlling operating costs in these fields 17 Operations in Mississippi to minimize the cost of saltwater disposal and pumping equipment. Bar graph showing the Ultimate Proved Reserves at Davis Field in thousands of BOE from the time of acquisition by the Company.
1993 1994 1995 1996 --------- ---------- ---------- ---------- Remaining Reserves 2,605 2,906 3,473 3,387 Cumulative Production - 358 747 1,100 --------- ---------- ---------- ---------- Total 2,605 3,264 4,220 4,487 ========= ========== ========== ==========
Since acquiring the majority of the field in 1993, Denbury has undertaken an active redevelopment program including numerous workovers and two development wells. As a result of this work and continued reductions in operating costs, the Company has been able to steadily increase the proven reserves every year. During 1996, the Company drilled two successful horizontal wells to improve withdrawal efficiency with an additional well planned for 1997. Quitman The Quitman Field is located in Clarke County, Mississippi, 31 miles northeast of Laurel and near the Davis and Frances Creek Fields. The Company acquired the field as part of the Hess Acquisition and now operates seven producing wells and 13 shut-in wells. The Company owns an average working interest of 82%. In December 1996, net production from these wells averaged 641 Bbls/d. The Quitman Field was discovered in 1966 and has produced approximately 21 MMBbls from 18 separate reservoirs between 7,500 feet and 12,000 feet. The principal producing zones at Quitman are the Smackover formation and several sands in the Cotton Valley formation. Denbury has identified 24 prospective zones behind pipe in existing shut-in wells. Testing of these zones will begin during the second half of 1996. The Company also plans to upgrade production and saltwater disposal facilities in an attempt to lower operating costs. In 1997, the Company plans to evaluate the Quitman Field and the immediate vicinity, including Davis and Frances Creek Fields, with a 3-D seismic survey. The Company believes that this survey will aid in the accurate evaluation of the existing reservoir and could lead to the discovery of new producing horizons. (One illustration, not incorporated by reference - see prefacing comment on Exhibit 13 Cover Page.) South Thompson Creek The South Thompson Creek Field is located in Wayne County, Mississippi, about 23 miles southeast of Laurel. Denbury operates three wells in the field with a 100% working interest. The South Thompson Creek Field is an anticline which has produced a total of 3.9 MMBbls since its discovery in 1960 from sandstone reservoirs in the Hosston, Rodessa and Tuscaloosa formations. Denbury first acquired an interest in the field in 1993 and increased its ownership in 1995 by acquiring the apex of the field. Subsequently, in 1995, the Company drilled 18 Operations in Mississippi its first horizontal well and in April 1996, Denbury acquired the remaining interest in the field as part of the Ottawa Acquisition. A second horizontal well was drilled in May 1996. During December 1996, the field produced an average of 290 Bbls/d and 2,000 barrels of saltwater per day. In 1997, the Company may drill a third horizontal well in the field pending continued evaluation of the first two horizontal wells. In addition, there are two shut-in wells which have recompletion potential. West Yellow Creek The West Yellow Creek Field is located 28 miles west of Laurel in Wayne County, Mississippi. Denbury operates seven producing oil wells and two saltwater disposal wells, with an average working interest of 97%. During December 1996, net production from the field averaged 264 Bbls/d. The Company's production is located in the central part of West Yellow Creek Field which has produced over 34 MMBbls since 1947, with most of the production being from the Eutaw formation at 5,000 feet. Production also occurs from multiple sands in the Tuscaloosa and Washita-Fredericksburg formations. This Tuscaloosa and Washita-Fredericksburg production, discovered in 1966, was essentially abandoned prior to 1993, when the Company acquired its first interests in the field. The Company began a drilling program in 1993 which continued through 1994. By a combination of successful drilling and additional production acquisitions, the Company was able to increase its net production from 40 Bbls/d in 1993 to 250 Bbls/d in 1995. In 1996, the Company acquired an additional 50% working interest in the operated wells through the Ottawa Acquisition. Sandersville The Sandersville Field is located about 12 miles northeast of Laurel, Mississippi. The field produces heavy oil from shallow sands of the Eutaw and Christmas formations along with large amounts of saltwater. The Sandersville Field was first purchased in late 1994 when Denbury acquired a 97% working interest in 15 active and inactive wells. During 1996, the Company completed a rework of six producing wells and two saltwater disposal wells, and net production in December 1996 averaged 229 Bbls/d. Sandersville Field is a four-mile-long structure with oil trapped in multiple sands at around 5,000 feet. Historically, the recovery of oil has been low and may be enhanced by horizontal drilling. The Company plans to drill these horizontal wells at Sandersville during 1997. Richton Dome In late 1996, Denbury entered into an agreement with another Company to drill a horizontal well into an oil reservoir at Richton Dome, located in Perry County, Mississippi. Denbury will have 50% working interest in the project, which will test a heavy oil section in the Eutaw at 6,000 feet. Depending upon the success of the first well, several additional drill sites could be feasible. Other Mississippi The Company currently owns interests in eight outside operated wells at Dexter Field, with an average 56% working interest. These interests were acquired in several transactions between 1992 and 1996. During December 1996, average net production from these wells was 2.2 MMcf/d. The Company plans to drill a development well in this field in 1997. Denbury operates seven wells in the Puckett Field with an average working interest of 94%. In December 1996, average net production from these wells was 97 Bbls/d. Current plans are to produce the current zones and then recomplete these wells into uphole horizons. There are presently 13 zones identified behind pipe for future development. In addition, Denbury operates wells in North Clara, Diamond, Lake Utopia, Bolton and Edwards Fields. 19 Selected Abbreviations and Financial Table of Contents Selected Abbreviations Bbls ~ Barrels of oil Bbl/d ~ Barrels of oil produced per day Bcf ~ Billion cubic feet of natural gas BOE ~ Barrel of oil equivalent using the ratio of one barrel of crude oil to 6 Mcf of natural gas BOE/d ~ Barrel of oil equivalent produced per day Btu ~ British thermal unit MBbls ~ Thousand barrels of oil MBOE ~ Thousand BOE MBOE/d ~ Thousand barrels of oil equivalent produced per day MBtu ~ Thousand Btu Mcf ~ Thousand cubic feet of natural gas Mcf/d ~ One thousand cubic feet of natural gas produced per day MMBbls ~ Million barrels of oil MMBOE ~ Million BOE MMBtu ~ Million Btu MMcf ~ Million cubic feet of natural gas MMcf/d ~ Million cubic feet of natural gas produced per day Tcf ~ Trillion cubic feet of natural gas Financial Table of Contents Management's Discussion & Analysis 21 Independent Auditors' Report 28 Financial Statements 29 Shareholder Information 48 20 Management's Discussion and Analysis of Financial Condition and Results of Operations Denbury is an independent energy company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. Since 1993, after having disposed of its Canadian oil and natural gas properties, the Company has focused its operations primarily onshore in Louisiana and Mississippi. Over the last three years, the Company has achieved rapid growth in proved reserves, production and cash flow by concentrating on the acquisition of properties which it believes have significant upside potential and through the efficient development, enhancement and operation of those properties. Bar graph showing the Company's expenditures on acquisitions (in millions): 1994 1995 1996 ---------- ---------- ---------- New acquisitions $ 0.3 $ 14.2 $ 41.4 Incremental acquisitions 6.3 2.6 7.0 ---------- ---------- ---------- Total $ 6.6 $ 16.8 $ 48.4 ========== ========== ========== Acquisition of Hess Properties The Company completed several property acquisitions during 1996, the largest of which was the acquisition of producing oil and natural gas properties in Mississippi, Louisiana, and Alabama, plus certain overriding royalty interests in Ohio, for approximately $37.2 million from Amerada Hess, effective May 1, 1996 (the "Hess Acquisition"). The average daily production from the properties included in the Hess Acquisition during May and June 1996, the first two months of ownership, was approximately 2,945 BOE/d. By December, 1996 the Company had increased the production on these properties to approximately 3,400 BOE/d. As of December 31, 1996, in the Company's independent reserve report (the "December Report"), the properties in this acquisition had estimated net proved reserves of approximately 9.5 MMBOE with a discounted present value using a 10% discount rate ("PV10 Value") of $96.1 million. This compares to approximately 5.9 MMBOE of net proved reserves and a $43.1 million PV10 Value on these same properties as of July 1, 1996 in the Company's mid-year independent reserve report (the "July Report"). The December Report was calculated using year-end prices which were based on a West Texas Intermediate ("WTI") price of $23.39 per Bbl and a NYMEX Henry Hub price of $3.90 per MMBTU, with these representative prices adjusted by field to arrive at the appropriate corporate net price, as compared to oil and gas prices of $20.00 and $2.65, respectively, in the July Report. For comparative purposes, the Company's independent engineer also prepared a December 31, 1996 reserve report using a WTI price of $21.00 per Bbl and a NYMEX price of $2.40 per MMBtu, with these prices also adjusted by field (the "Modified December Report"). The PV10 Value in the Modified December Report was $72.0 million for the properties acquired in the Hess Acquisition. Ottawa and Other 1996 Acquisitions In addition to the Hess Acquisition, the Company completed other acquisitions totaling $11.2 million. The largest of these was an acquisition of additional working interests in five Mississippi oil and natural gas properties in which the Company already owned an interest, plus certain overriding royalty interests in other areas, which were acquired during April 1996 for approximately $7.5 million (the "Ottawa Acquisition"). The average daily production for the properties in the Ottawa Acquisition during April, May and June 1996, the first three months of ownership, was approximately 600 BOE/d. By December, 1996 the Company had increased the net production on these properties to approximately 650 BOE/d. In addition to the Ottawa Acquisition, the Company spent an additional $3.7 million on nine other acquisitions, primarily in Louisiana. The properties in these other acquisitions were producing approximately 360 BOE/d as of December 1996. The Company's estimated net proved reserves in the December Report for all of these other acquisitions, including the Ottawa Acquisition, totaled approximately 4.0 MMBOE with a PV10 Value of $47.4 million. This compares to approximately 3.3 MMBOE and a $24.1 million PV10 Value as of July 1, 1996 in the July Report. The PV10 Value in the Modified December Report was $29.4 million for these same properties. 21 Management's Discussion and Analysis of Financial Condition and Results of Operations Bar graph comparing the debt and equity of the Company (in thousands): 1994 1995 1996 --------- --------- ---------- Equity $ 25,962 $ 53,501 $ 142,504 Debt 16,376 3,371 125 1996 Capital Adjustments During 1996, the Company issued 250,000 Common Shares for the conversion of its 6 3/4% Convertible Debentures and 75,000 Common Shares for the exercise of half of its Cdn. $8.40 Warrants. On October 10, 1996, the Company effected a one-for-two reverse split of its outstanding Common Shares and effective October 15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures ("Debentures") were converted by their holders into 316,590 Common Shares. At a special meeting held on October 9, 1996, the shareholders of the Company approved an amendment to the terms of the Convertible First Preferred Shares, Series A ("Convertible Preferred") to allow the Company to require the conversion of the Convertible Preferred at any time, provided that the conversion rate in effect as of January 1, 1999 would apply to any required conversion prior to that date. The Company converted all of the 1,500,000 shares of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at a net price to the Company of $12.035 per share as part of a public offering with net proceeds to the Company of approximately $58.8 million (the "Public Offering"). The Company's largest shareholder, the Texas Pacific Group ("TPG"), purchased 800,000 of these shares at $12.035 per share. New Credit Facility In order to fund the 1996 acquisitions and improve the terms and increase the size of its previous credit facility, the Company entered into a new $150.0 million Credit Facility during the second quarter of 1996. This new facility had a borrowing base as of December 31, 1996 of $60.0 million. The Credit Facility is a two-year revolving credit facility that converts to a three-year term loan in May 1998, unless renewed or extended. The Credit Facility is secured by virtually all the Company's oil and natural gas properties and interest is payable at either the bank's prime rate or, depending on the percentage of the borrowing base that is outstanding, at rates ranging from LIBOR plus 7/8% to LIBOR plus 13/8%. The Credit Facility has several restrictions including, among others: (i) a prohibition on the payment of dividends, (ii) a requirement for a minimum equity balance, (iii) a requirement to maintain positive working capital as defined and (iv) a prohibition of most debt and corporate guarantees. Capital Resources and Liquidity As outlined in the following table, in each of the last three years, the Company has made capital expenditures which required additional debt and equity capital to supplement cash flow from operations.
YEAR ENDED DECEMBER 31, ---------------------------------------- DOLLARS IN THOUSANDS 1996 1995 1994 ----------- ----------- ------------ Acquisitions of oil and natural gas properties... $ 48,407 $ 16,763 $ 6,606 Oil and natural gas expenditures................. 38,450 11,761 10,297 ----------- ----------- ------------ Total................................... $ 86,857 $ 28,524 $ 16,903 =========== =========== ============
Two pie charts showing the capitalization of the Company (in thousands): September 30, December 31, 1996 1996 ----------------- --------------- Debt $ 46,867 $ 125 Preferred stock 16,153 - Common stock 53,213 130,323 Retained earnings 7,777 12,181 22 Management's Discussion and Analysis of Financial Condition and Results of Operations Stacked bar graph showing the capital expenditures of the Company (in thousands): 1994 1995 1996 --------- ----------- ----------- Development $ 10,297 $ 11,761 $ 38,450 Acquisitions 6,606 16,763 48,407 --------- ----------- ----------- Total $ 16,903 $ 28,524 $ 86,857 ========= =========== =========== Since January 1, 1994, the Company has made total capital expenditures of $132.3 million, paid off all but $100,000 of its bank debt and increased its working capital by approximately $13.9 million. This was funded by the issuance of equity ($102.9 million, including the Convertible Preferred) and cash generated by operations ($49.7 million). During 1996, the Company's funds were provided by operating cash flow and equity, although the Company did use bank debt during the year. The Company began 1996 with $100,000 of outstanding bank debt, borrowed $47.9 million during the year, paid off the debt with the proceeds from the Public Offering in October and ended the year with $100,000 of bank debt outstanding. As of December 31, 1996, the Company had working capital of $12.5 million and virtually no debt outstanding. The Company has budgeted capital expenditures for 1997 of between $60 and $70 million. Although the Company's projected cash flow is highly variable and difficult to predict as it is dependent on product prices, drilling success, and other factors, these projected expenditures are expected to exceed the Company's cash flow during 1997. However, as of December 31, 1996, the Company has an unused borrowing base of $60.0 million to fund any potential cash flow deficits. If external capital resources are limited or reduced in the future, the Company can also adjust its capital expenditure program accordingly. However, such adjustments could limit, or even eliminate, the Company's future growth. In addition to its internal capital expenditure program, the Company has historically required capital for the acquisition of producing properties, which have been a major factor in the Company's rapid growth during recent years. There can be no assurance that suitable acquisitions will be identified in the future or that any such acquisitions will be successful in achieving desired profitability objectives. Without suitable acquisitions or the capital to fund such acquisitions, the Company's future growth could be limited or even eliminated. New Accounting Pronouncement The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has adopted Statement of Position 96-1, "Environmental Remediation Liabilities," which provides guidance on the recognition, measurement, display and disclosure of environmental remediation liabilities. The Statement is effective for the Company's 1997 fiscal year. Management evaluated such Statement and believes that it will not have a material effect on the financial position or results of operations of the Company. Sources and Uses of Funds During 1996, the Company spent approximately $33.4 million on oil and natural gas development expenditures, $48.4 million on the previously discussed oil and natural gas acquisitions, and approximately $5.1 million on geological, geophysical and acreage expenditures. The development expenditures included $15.5 million spent on drilling and the balance of $17.9 million was spent on workover costs. These expenditures were funded during the year by bank debt, available cash and cash flow from operations, although the bank debt was retired with the proceeds from the Public Offering. During 1995, the Company made $28.5 million in capital expenditures, with the single largest component being a $10.0 million acquisition of seven producing wells in the Gibson and Humphreys Fields located near the Company's other properties in suthern Louisiana (the "Gibson Acquisition"). The balance of 1995 acquisition expenditures were for additional interests in the Company's Lirette Field in Louisiana ($2.9 million), interests in the Bully Camp Field, also in Louisiana ($2.1 million), and a few smaller acquisitions in both Mississippi and Louisiana. During 1995, the Company also spent $1.9 million drilling four wells in Mississippi, $1.1 million for acreage, geological and geophysical and delay rentals, and the balance of $8.1 million for workovers of existing properties. The 1995 expenditures were funded on an interim basis with cash flow from operations ($9.4 million) and bank debt ($19.4 million), which was repaid in December 1995 with a portion of the $39.5 million of net proceeds from the private placement of equity with TPG. 23 Management's Discussion and Analysis of Financial Condition and Results of Operations Capital expenditures for 1994 were $16.9 million and included $10.3 million of development costs primarily expended on natural gas properties in Louisiana, with the balance of $6.6 million expended on acquisitions of properties primarily in Louisiana, of which $5.5 million was spent on acquiring additional working interests in existing Company-operated properties. Expenditures in 1994 were principally funded by $6.2 million of cash provided by operations and net incremental debt of $8.8 million, of which $1.5 million came from the issuance of unsecured convertible debentures and the balance from bank debt. RESULTS OF OPERATIONS Operating Income During the last three years, operating income has increased significantly as outlined in the following chart. Oil and gas revenue increased as a result of the increased oil and gas production and increases in oil and gas product prices.
Year ended December 31 - ----------------------------------------------------------------------------------------------------------- 1996 1995 1994 - ----------------------------------------------------------------------------------------------------------- OPERATING INCOME (THOUSANDS) Oil sales $ 28,475 $ 10,852 $ 6,767 Natural gas sales 24,405 9,180 5,925 Less production expenses (13,495) (6,789) (4,309) ------------ ---------- ----------- Operating income $ 39,385 $ 13,243 $ 8,383 ------------ ---------- ----------- UNIT PRICES Oil price per Bbl $ 18.98 $ 14.90 $ 13.84 Gas price per Mcf 2.73 1.90 1.78 NETBACK PER BOE Sales price $ 17.69 $ 13.05 $ 12.17 Production expenses (4.51) (4.42) (4.13) ------------ ---------- ----------- $ 13.18 $ 8.63 $ 8.04 ------------ ---------- ----------- AVERAGE DAILY PRODUCTION VOLUME: Bbls 4,099 1,995 1,340 Mcf 24,406 13,271 9,113 BOE 8,167 4,207 2,858 - -----------------------------------------------------------------------------------------------------------
Bar graph showing the average price received by the Company per barrel of oil: 1994 $ 13.84 1995 14.90 1996 18.98 Production increases have been fueled by both internal growth from the Company's development and exploration programs and from the acquisition of producing properties. Production on a BOE/d basis increased 47% between 1994 and 1995 with approximately 240 BOE/d attributable to the Gibson Acquisition and the balance of approximately 1,109 BOE/d primarily attributable to internal growth. Between 1995 and 1996, production increased 94% with approximately 2,550 BOE/d attributable to the properties included in the Hess and Ottawa Acquisitions and 750 BOE/d attributable to properties included in the Gibson Acquisition. The balance of approximately 660 BOE/d was attributable to internal growth on other properties. Oil and gas revenue has increased not only because of the large increase in production, but also due to improved product prices. Between 1994 and 1995, product prices increases were relatively modest with an 8% increase in oil prices and a 7% increase in natural gas prices. The Company also realized an $800,000 gas hedging gain during 1995 which added $.17 per Mcf to its average natural gas price. The Company did not have any oil or natural gas hedges in place during 1996, nor does it have any currently in place due to the relatively strong commodity prices and the reduced debt levels of the Company. During 1996, product prices increased substantially with a 27% increase in the average oil price and a 44% increase in the average natural gas price. Coupled with the production increases, the Company's oil and natural gas revenue increased 164%, or $32.8 million, from 1995 to 1996. Approximately $16.5 million of the increase was related to properties acquired in the Hess Bar graph showing the average price received by the Company per Mcf of natural gas: 1994 $ 1.78 1995 1.90 1996 2.73 and Ottawa Acquisitions, approximately $5.4 million to properties acquired in the Gibson Acquisition, approximately $7.7 million due to the increase in product prices and the balance of approximately $3.2 million due to increased production from internal growth on other properties. Production expenses increased each year along with the increases in production. On a BOE basis, production expenses increased 7% from 1994 to 1995 and increased 2% from 1995 to 1996. The increases were largely attributable to the changes in the mix of properties as the Mississippi oil properties tend to have a higher operating cost per BOE than the Louisiana gas properties. During the first two months of ownership (May and June 1996), the production expenses averaged $6.27 per BOE on the Hess Acquisition properties which were more heavily weighted toward Mississippi oil than Louisiana gas. After assuming operations, these averages were brought more in line with the Company averages through cost savings and increased production levels. For the year (May through December, 1996) production expenses on these properties averaged $5.35 per BOE. General and Administrative Expenses General and administrative ("G&A") expenses have increased as outlined below along with the Company's growth.
Year ended December 31, - -------------------------------------------------------------------------------------------------------- 1996 1995 1994 - -------------------------------------------------------------------------------------------------------- NET G&A EXPENSES (THOUSANDS) Gross expenses $ 8,407 $ 3,900 $ 2,475 State franchise taxes 213 100 65 Operator recoveries (2,916) (1,438) (890) Capitalized exploration expenses (1,224) (630) (480) --------------------------------------------- Net expenses $ 4,480 $ 1,932 $ 1,170 --------------------------------------------- Average G&A cost per BOE $ 1.50 $ 1.25 $ 1.12 Employees as of December 31 122 51 27 - --------------------------------------------------------------------------------------------------------
On a BOE basis, these costs increased 12% from 1994 to 1995 and increased 20% from 1995 to 1996. Part of the increase in 1995 was attributable to $190,000 of costs ($0.12 per BOE) related to non-recurring personnel changes. As a result of improved financial results during the first quarter of 1996 and other factors, the Company conducted a review of salaries and awarded increases and bonuses in February 1996 to its employees. Bonuses, including related payroll taxes, amounted to approximately $225,000 ($.08 per BOE). During 1996, the Company also accrued $545,000 ($.18 per BOE) for bonuses which were awarded in February 1997. In addition, the Company began to increase its staff levels during the second quarter of 1996 to handle the Hess Acquisition, but was not entitled to any operator's overhead recovery on these properties until July 15, 1996, further fueling an increase in general and administrative cost per BOE, as Amerada Hess remained the operator of record until that date. Stacked bar graph showing the cash flow, interest, G&A and production costs of the Company per BOE: 1994 1995 1996 ---------- ------------- ------------- Revenue $ 12.17 $ 13.05 $ 17.69 Production expense (4.13) (4.42) (4.51) G&A (1.12) (1.25) (1.50) Interest expense (0.99) (1.26) (0.26) ---------- ------------- ------------- Cash flow $ 5.93 6.12 $ 11.42 ========== ============= ============= 24 Management's Discussion and Analysis of Financial Condition and Results of Operations Interest and Financing Expenses
YEAR ENDED DECEMBER 31, - -------------------------------------------------------------------------------------------------------- AMOUNTS IN THOUSANDS EXCEPT PER UNIT AMOUNTS 1996 1995 1994 - -------------------------------------------------------------------------------------------------------- Interest expense $ 1,993 $ 2,085 $ 1,146 Non-cash interest expense (459) (90) (86) -------------------------------------- Cash interest expense 1,534 1,995 1,060 Interest and other income (769) (77) (23) -------------------------------------- Net interest expense $ 765 $ 1,918 $ 1,037 - -------------------------------------------------------------------------------------------------------- Average interest cost per BOE $ 0.26 $ 1.26 $ 0.99 Average debt outstanding $ 19,500 $ 21,400 $ 12,200 Average interest rate 7.9% 9.3% 8.7% Ratio of earnings to fixed charges 4.6 1.5 2.6 - -------------------------------------------------------------------------------------------------------- Imputed preferred dividend $ 1,281 $ - $ - Loss on early extinguishment of debt 440 200 - - --------------------------------------------------------------------------------------------------------
During both 1995 and 1996, the Company incurred bank debt in order to fund property acquisitions. However, in both years this debt was retired before year-end. In 1995, the bank debt was repaid with proceeds from the private placement of equity with TPG and in 1996 with proceeds from the Public Offering. The private placement of equity in December 1995 with TPG included 1.5 million shares of Convertible Preferred. During 1996, the Company recognized $1.3 million of charges representing the imputed preferred dividend until October 30, 1996 when the Convertible Preferred was converted into 2.8 million Common Shares. Under Canadian generally accepted accounting principles ("GAAP"), this dividend was reported as an operating expense, while under U.S. GAAP this would not be an expense but it would be deducted from net income to arrive at net income attributable to the common shareholders. In addition to paying off its bank debt and converting the Convertible Preferred into common equity during 1996, the Company also converted its remaining subordinated debt into common equity, leaving the Company essentially debt-free as of December 31, 1996. During 1996, the Company had a $440,000 charge relating to a loss on early extinguishment of debt. These costs related to the remaining unamortized debt issue costs of the Company's prior credit facility which was replaced in May 1996, as previously discussed. The Company also had a charge of $200,000 during the first half of 1995 for the same type of expense relating to a previous bank refinancing. Under U.S. GAAP, a loss on early extinguishment of debt would be an extraordinary item rather than a normal operating expense as required by Canadian GAAP. Depletion, Depreciation and Site Restoration Depletion, depreciation and amortization ("DD&A") has increased along with the additional capitalized cost and increased production. DD&A per BOE has increased 30% from 1994 to 1995 and 15% from 1995 to 1996 primarily due to 59% of the 1995 capital expenditures and 56% of the 1996 expenditures relating to property acquisitions, which had a higher per unit cost for the Company than those reserves added by development expenditures. The Company also provides 25 Management's Discussion and Analysis of Financial Condition and Results of Operations for the estimated future costs of well abandonment and site reclamation, net of any anticipated salvage, on a unit-of-production basis. This provision is included in the DD&A expense and has increased each year along with an increase in the number of properties owned by the Company.
YEAR ENDED DECEMBER 31, - -------------------------------------------------------------------------------------------------------- AMOUNTS IN THOUSANDS EXCEPT PER UNIT AMOUNTS 1996 1995 1994 - -------------------------------------------------------------------------------------------------------- Depletion and depreciation $ 17,533 $ 7,918 $ 4,177 Site restoration provision 371 104 32 -------------------------------------- Total amortization $ 17,904 $ 8,022 $ 4,209 -------------------------------------- Average DD&A cost per BOE $ 5.99 $ 5.22 $ 4.03 - --------------------------------------------------------------------------------------------------------
Income Taxes Due to a net operating loss of the U.S. subsidiary each year for tax purposes, the Company does not have any current tax provision. The deferred tax provision as a percentage of net income has varied depending on the mix of Canadian and U.S. expenses. The rate declined from 1994 to 1995 as there were less Canadian expenses, but increased again slightly in 1996 due to the non-deductible imputed preferred dividend and interest on the subordinated debt.
YEAR ENDED DECEMBER 31, - -------------------------------------------------------------------------------------------------------- 1996 1995 1994 - -------------------------------------------------------------------------------------------------------- Deferred income taxes (thousands) $ 5,312 $ 367 $ 718 Average income tax costs per BOE $ 1.78 $ 0.24 $ 0.69 Effective tax rate 38% 34% 38% - --------------------------------------------------------------------------------------------------------
Net Income Primarily as a result of increased production and improved product prices, net income and cash flow from operations increased substantially between 1995 and 1996 as outlined below. Between 1994 and 1995, net income decreased 39% as a result of certain nonrecurring charges and a disproportionate increase in DD&A as compared to the increase in revenue.
YEAR ENDED DECEMBER 31, - -------------------------------------------------------------------------------------------------------- AMOUNTS IN THOUSAND EXCEPT PER SHARE AMOUNTS 1996 1995 1994 - -------------------------------------------------------------------------------------------------------- Net income $ 8,744 $ 714 $ 1,163 Net income per common share: Primary $ 0.67 $ 0.10 $ 0.19 Fully diluted 0.62 0.10 0.19 Cash flow from operations (1) $ 34,140 $ 9,394 $ 6,185 - -------------------------------------------------------------------------------------------------------- (1) Represents cash flow provided by operations, exclusive of the net change in non-cash working capital balances.
26 INDEPENDENT AUDITORS' REPORT To the Shareholders of Denbury Resources Inc. We have audited the consolidated balance sheets of Denbury Resources Inc. as at December 31, 1996 and 1995 and the consolidated statements of income, changes in shareholders' equity and cash flows for each of the years in the three year period ended December 31, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada and the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly in all material respects, the financial position of the Company as at December 31, 1996 and 1995 and the results of its operations and the changes in shareholders' equity and cash flows for each of the years in the three year period ended December 31, 1996, in accordance with accounting principles generally accepted in Canada. Deloitte & Touche Chartered Accountants Calgary, Alberta February 21, 1997 27 CONSOLIDATED BALANCE SHEETS
AMOUNTS IN THOUSANDS OF U.S. DOLLARS DECEMBER 31, ----------------------------- 1996 1995 ------------- ------------- CURRENT ASSETS Cash and cash equivalents........................................ $ 13,453 $ 6,553 Accrued production receivable.................................... 11,906 3,212 Trade and other receivables...................................... 3,643 1,160 ------------- ------------- Total current assets .................................. 29,002 10,925 ------------- ------------- PROPERTY AND EQUIPMENT (USING FULL COST ACCOUNTING) Oil and natural gas properties................................... 159,724 72,510 Unevaluated oil and natural gas properties....................... 6,413 7,085 Less accumulated depreciation and depletion...................... (31,141) (13,982) ------------- ------------- Net property and equipment................................ 134,996 65,613 ------------- ------------- OTHER ASSETS........................................................ 2,507 1,103 ------------- ------------- TOTAL ASSETS............................................. $ 166,505 $ 77,641 ============= ============= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities..................... $ 10,903 $ 2,872 Oil and gas production payable............................... 5,550 1,014 Current portion of long-term debt ........................... 67 177 ------------- ------------- Total current liabilities................................ 16,520 4,063 ------------- ------------- LONG-TERM LIABILITIES Long-term debt................................................... 125 3,474 Provision for site reclamation costs............................. 613 242 Deferred income taxes and other.................................. 6,743 1,361 ------------- ------------- Total long-term liabilities.............................. 7,481 5,077 ------------- ------------- CONVERTIBLE FIRST PREFERRED SHARES, SERIES A 1,500,000 shares authorized, issued and outstanding at December 31, 1995................................. - 15,000 ------------- ------------- SHAREHOLDERS' EQUITY Common shares, no par value, unlimited shares authorized; outstanding - 20,055,757 and 11,428,809 shares at December 31, 1996 and December 31, 1995 respectively......... 130,323 50,064 Retained earnings................................................ 12,181 3,437 ------------- ------------- Total shareholders' equity............................... 142,504 53,501 ------------- ------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............... $ 166,505 $ 77,641 ============= =============
Approved by the Board: /s/ Gareth Roberts /s/ Wieland F. Wettstein - --------------------- ------------------------- Gareth Roberts Wieland F. Wettstein Director Director See Notes to Consolidated Financial Statements. 28 Consolidated Statements of Income
YEAR ENDED DECEMBER 31, -------------------------------------- AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS (U.S. DOLLARS) 1996 1995 1994 ----------- ---------- ---------- REVENUES Oil, natural gas and related product sales................... $ 52,880 $ 20,032 $ 12,692 Interest income.............................................. 769 77 23 ----------- ---------- ---------- Total revenues......................................... 53,649 20,109 12,715 ----------- ---------- ---------- EXPENSES Production................................................... 13,495 6,789 4,309 General and administrative................................... 4,267 1,832 1,105 Interest..................................................... 1,993 2,085 1,146 Imputed preferred dividends.................................. 1,281 - - Loss on early extinguishment of debt......................... 440 200 - Depletion and depreciation................................... 17,904 8,022 4,209 Franchise taxes.............................................. 213 100 65 ----------- ---------- ---------- Total expenses........................................ 39,593 19,028 10,834 ----------- ---------- ---------- Income before income taxes........................................ 14,056 1,081 1,881 Provision for federal income taxes................................ (5,312) (367) (718) ----------- ---------- ---------- NET INCOME........................................................ $ 8,744 $ 714 $ 1,163 =========== ========== ========== NET INCOME PER COMMON SHARE....................................... Primary................................................ $ 0.67 $ 0.10 $ 0.19 Fully-diluted.......................................... $ 0.62 $ 0.10 $ 0.19 Average number of common shares outstanding....................... 13,104 6,870 6,240 =========== ========== ==========
See Notes to Consolidated Financial Statements 29 Consolidated Statements of Cash Flows
YEAR ENDED DECEMBER 31, -------------------------------------- AMOUNTS IN THOUSANDS OF U.S. DOLLARS 1996 1995 1994 ---------- ----------- ----------- CASH FLOW FROM OPERATING ACTIVITIES: Net income.................................................. $ 8,744 $ 714 $ 1,163 Adjustments needed to reconcile to net cash flow provided by operations: Depreciation, depletion and amortization................ 17,904 8,113 4,304 Deferred income taxes................................... 5,312 367 718 Imputed preferred dividend.............................. 1,281 - - Loss on early extinguishment of debt.................... 440 200 - Other................................................... 459 - - ----------- ----------- ------------ 34,140 9,394 6,185 Changes in working capital items relating to operations: Accrued production receivable........................... (8,694) (1,303) (986) Trade and other receivables............................. (1,508) (168) (124) Accounts payable and accrued liabilities................ 6,711 (1,660) 1,581 Oil and gas production payable.................... 4,536 490 261 ---------- ----------- ----------- NET CASH FLOW PROVIDED BY OPERATIONS........................... 35,185 6,753 6,917 ---------- ----------- ----------- CASH FLOW USED FOR INVESTING ACTIVITIES: Oil and natural gas expenditures........................ (38,450) (11,761) (10,297) Acquisition of oil and natural gas properties........... (48,407) (16,763) (6,606) Net purchases of other assets........................... (1,726) (560) (122) Acquisition of subsidiary, net of cash acquired......... 209 - - ---------- ----------- ----------- NET CASH USED FOR INVESTING ACTIVITIES......................... (88,374) (29,084) (17,025) ---------- ----------- ----------- CASH FLOW FROM FINANCING ACTIVITIES: Bank borrowings......................................... 47,900 19,350 9,835 Bank repayments......................................... (47,900) (34,200) (2,485) Issuance of subordinated debt........................... - 1,772 1,451 Issuance of common stock................................ 60,664 26,825 367 Issuance of preferred stock............................. - 15,000 - Costs of debt financing................................. (411) (493) (122) Other................................................... (164) (82) 62 ---------- ----------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES...................... 60,089 28,172 9,108 ---------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... 6,900 5,841 (1,000) Cash and cash equivalents at beginning of year................. 6,553 712 1,712 ---------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR....................... $ 13,453 $ 6,553 $ 712 ========== =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for interest................. $ 1,621 $ 2,127 $ 1,027 SUPPLEMENTAL DISCLOSURE OF FINANCING ACTIVITIES: Conversion of subordinated debt to common stock....... $ 3,314 - - Conversion of preferred stock to common stock......... 16,281 - - Assumption of liabilities in acquisition.............. 1,321 - -
See Notes to Consolidated Financial Statements 30 CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY
COMMON SHARES (NO PAR VALUE) ------------ ------------ RETAINED DOLLAR AMOUNTS IN THOUSANDS OF U.S. DOLLARS SHARES AMOUNT EARNINGS TOTAL ------------ ------------ ----------- ---------- BALANCE - JANUARY 1, 1994 $ 6,208,417 $ 22,872 $ 1,560 $ 24,432 ------------ ------------ ----------- ---------- Issued pursuant to employee stock option plan......... 96,250 367 - 367 Net income............................................ - - 1,163 1,163 ------------ ------------ ----------- ---------- BALANCE - DECEMBER 31, 1994 6,304,667 23,239 2,723 25,962 ------------ ------------ ----------- ---------- Issued pursuant to employee stock option plan......... 10,000 54 - 54 Private placement of Special Warrants exchanged....... 614,143 2,314 - 2,314 Private placement of common shares.................... 4,499,999 24,457 - 24,457 Net income............................................ - - 714 714 ------------ ------------ ----------- ---------- BALANCE - DECEMBER 31, 1995 11,428,809 50,064 3,437 53,501 ------------ ------------ ----------- ---------- Issued pursuant to employee stock option plan......... 197,675 1,070 - 1,070 Issued pursuant to employee stock purchase plan....... 31,311 358 - 358 Public placement of common shares..................... 4,940,000 58,776 - 58,776 Conversion of preferred stock......................... 2,816,372 16,281 - 16,281 Conversion of warrants................................ 75,000 460 - 460 Conversion of subordinated debt....................... 566,590 3,314 - 3,314 Net income............................................ - - 8,744 8,744 ------------ ------------ ----------- ---------- BALANCE - DECEMBER 31, 1996 20,055,757 $ 130,323 $ 12,181 $ 142,504 ============ ============ =========== ==========
See Notes to Consolidated Financial Statements 31 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 NOTE 1. SIGNIFICANT ACCOUNTING POLICIES The Company's operating activities are related to exploration, development and production of oil and natural gas in the United States. All of the Canadian operations were sold effective September 1, 1993. The Company's name was changed on June 7, 1994, from Canadian Newscope Resources Inc. to Newscope Resources Ltd. and again on December 21, 1995 to Denbury Resources Inc. On October 9, 1996 the shareholders of the Company approved an amendment to the Articles of Continuance to consolidate the number of issued and outstanding Common Shares on the basis of one Common Share for each two Common Shares outstanding. All applicable shares and per share data have been adjusted for the reverse stock split. Principles of Consolidation The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include the accounts of the Company and its wholly owned subsidiaries, Denbury Holdings Ltd., Denbury Management, Inc. and Denbury Marine L.L.C. and the Company's equity in the operation of its 50% owned subsidiary, Brymore Energy Corporation ("Brymore"). The Company acquired the remaining 50% of Brymore effective May 1, 1996 and began consolidating all of Brymore as of that date. All material intercompany balances and transactions have been eliminated. Oil and Natural Gas Operations A) CAPITALIZED COSTS The Company follows the full-cost method of accounting for oil and natural gas properties. Under this method, all costs related to the exploration for and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing the Company's activities undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells and general and administrative expenses directly related to exploration and development activities. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves in which case a gain or loss is recognized. B) DEPLETION AND DEPRECIATION The costs capitalized, including production equipment, are depleted or depreciated on the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units based upon the relative energy content which is six thousand cubic feet of natural gas to one barrel of crude oil. C) SITE RECLAMATION Estimated future costs of well abandonment and site reclamation, including the removal of production facilities at the end of their useful life, are provided for on a unit-of-production basis. Costs are based on engineering estimates of the anticipated method and extent of site restoration, valued at year-end prices, net of estimated salvage value, and in accordance with the current legislation and industry practice. The annual provision for future site reclamation costs is included in depletion and depreciation expense. D) CEILING TEST The capitalized costs less accumulated depletion, depreciation, related deferred taxes and site reclamation costs are limited to an amount which is not greater than the estimated future net revenue from proved reserves using period-end prices less estimated future site restoration and abandonment costs, future production-related general and administrative expenses, financing costs and income taxes, plus the cost (net of impairments) of undeveloped properties. E) JOINT INTEREST OPERATIONS Substantially all of the Company's oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities. 32 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 FOREIGN CURRENCY TRANSLATION Since 1993 when the Company sold its Canadian oil and natural gas properties, virtually all of the Company's assets are located in the United States. These assets and the United States operations are accounted for and reported in U.S. dollars and no translation is necessary. The minor amount of Canadian assets and liabilities is translated to U.S. dollars using year-end exchange rates and any Canadian operations, which are principally minor administrative and interest expenses, are translated using the historical exchange rate. Earnings per Share Net income per common share is computed by dividing the net income attributable to common shareholders by the weighted average number of shares of common stock outstanding. The conversion of the Convertible First Preferred Shares, Series A ("Convertible Preferred") was anti-dilutive and was not included in the calculation of earnings per share. In computing fully diluted earnings per share, the stock options, warrants and convertible debt instruments were dilutive for the year ended December 31, 1996 and were assumed to be converted or exercised as of the first of the year with the proceeds used to reduce interest expense. For the prior years, these instruments were either anti-dilutive or immaterial. Statement of Cash Flows For purposes of the Statement of Cash Flows, cash equivalents include time deposits, certificates of deposit and all liquid debt instruments with maturities at the date of purchase of three months or less. Revenue Recognition The Company follows the "sales method" of accounting for its oil and natural gas revenue whereby the Company recognizes sales revenue on all oil or natural gas sold to its purchasers, regardless of whether the sales are proportionate to the Company's ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 1996 and 1995, the Company's aggregate oil and natural gas imbalances were not material to its consolidated financial statements. The Company recognizes revenue and expenses of purchased producing properties commencing from the closing or agreement date, at which time the Company also assumes control. Financial Instruments with Off-balance Sheet Risk and Concentrations of Credit Risk The Company's product price hedging activities are described in Note 6 to the consolidated financial statements. Credit risk relating to these hedges is minimal because of the credit risk standards required for counter-parties and monthly settlements. The Company has entered into hedging contracts with only large and financially strong companies. The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments and trade and accrued production receivables. The Company's cash equivalents and short-term investments represent high-quality securities placed with various investment grade institutions. This investment practice limits the Company's exposure to concentrations of credit risk. The Company's trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. Also, the Company's more significant purchasers are large companies with excellent credit ratings. If customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. 33 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 Fair Value of Financial Instruments As of December 31, 1996 and December 31, 1995, the carrying value of the Company's debt and other financial instruments approximates its fair market value. The Company's bank debt is based on a floating interest rate and thus adjusts to market as interest rates change. The Company's other financial instruments are primarily cash, cash equivalents, short-term receivables and payables which approximate fair value due to the nature of the instrument and the relatively short maturities. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amount of certain assets, liabilities, revenues and expenses as of and for the reporting period. Estimates and assumptions are also required in the disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results may differ from such estimates. NOTE 2. PROPERTY AND EQUIPMENT Unevaluated Oil and Natural Gas Properties Excluded From Depletion Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 1996 and 1995 and the year in which they were incurred follows:
December 31, 1996 December 31, 1995 ---------------------------------- ------------------------------------------------ Costs Incurred During: Costs Incurred During: ---------------------- ----------------------------------- 1996 1995 Total 1995 1994 1993 Total ---------- ---------- --------- --------- -------- --------- ---------- AMOUNTS IN THOUSANDS Property acquisition cost. $ 2,614 $ 252 $ 2,866 $ 2,909 $ 1,230 $ 1,151 $ 5,290 Exploration costs......... 3,460 87 3,547 649 1,146 - 1,795 ---------- ---------- --------- --------- -------- --------- ---------- Total................. $ 6,074 $ 339 $ 6,413 $ 3,558 $ 2,376 $ 1,151 $ 7,085 ========== ========== ========= ========= ======== ========= ==========
Costs are transferred into the amortization base on an ongoing basis as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. General and administrative costs that directly relate to exploration and development activities that were capitalized during the period totaled $1,224,000, $630,000 and $480,000 for the years ended December 31, 1996, 1995 and 1994, respectively. Amortization per BOE was $5.99, $5.22, $4.03 for the years ended December 31, 1996, 1995 and 1994, respectively. NOTE 3. NOTES PAYABLE AND LONG-TERM INDEBTEDNESS December 31, ---------------------------- 1996 1995 ------------ ------------ AMOUNTS IN THOUSANDS Senior bank loan...................................$ 100 $ 100 Convertible debentures............................. - 3,296 Other notes payable................................ 92 255 ------------ ------------ 192 3,651 Less portion due within one year................... (67) (177) ------------ ------------ Total long-term debt......................$ 125 $ 3,474 ============ ============ Banks During 1996 the Company entered into a new $150 million credit facility with NationsBank of Texas ("NationsBank"). This refinancing closed on May 31, 1996 and has a borrowing base as of December 31, 1996 of $60 million. NationsBank is the agent bank and the facility includes two other banks. The credit facility is a two-year revolving credit facility that converts to a three year term loan in May 1998, unless renewed or extended. The credit facility is secured by virtually all the Company's oil and natural gas properties and interest is payable at either the bank's prime rate or, depending on the percentage of the borrowing base that is outstanding, ranging from LIBOR plus 7/8% to LIBOR plus 13/8%. This credit facility also has several restrictions including, among others: (i) a prohibition on the payment of dividends, (ii) a requirement for a minimum equity balance, (iii) a requirement to maintain positive working capital as defined, and (iv) a prohibition of most debt and corporate guarantees. As of December 31, 1996, the Company had $100,000 outstanding on this line of credit and $645,000 of letters of credit outstanding. Subordinated Debt On March 23, 1994, Denbury issued Cdn. $2,000,000 principal amount of 6 3/4% unsecured convertible debentures and on January 17, 1995, Denbury issued Cdn. $2,500,000 principal amount of 9 1/2% unsecured convertible debentures. These debentures were converted into 566,590 Common Shares during 1996. Indebtedness Repayment Schedule
The Company's indebtedness is repayable as follows: DECEMBER 31, 1996 ------------------------------------------------ OTHER NOTES AMOUNTS IN THOUSANDS BANK LOAN PAYABLE TOTAL - -------------------------------------------------- ---------------- ----------- YEAR 1997 ..............................$ - $ 67 $ 67 1998 .............................. 17 23 40 1999 .............................. 33 2 35 2000 .............................. 33 - 33 2001 .............................. 17 - 17 ------------- ---------------- ----------- Total indebtedness $ 100 $ 92 $ 192 ============= ================ ===========
NOTE 4. INCOME TAXES The Company's tax provision is as follows:
YEAR ENDED DECEMBER 31, -------------------------------------- AMOUNTS IN THOUSANDS EXCEPT PER UNIT AMOUNTS 1996 1995 1994 ---------- --------- ---------- Deferred Federal..........................................$ 5,312 $ 367 $ 718 State............................................ - - - ---------- --------- ---------- Total tax provision.................................$ 5,312 $ 367 $ 718 ========== ========= ==========
35 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 Income tax expense for the year varies from the amount that would result from applying Canadian federal and provincial tax rates to income before income taxes as follows:
YEAR ENDED DECEMBER 31, ---------------------------------- AMOUNTS IN THOUSANDS 1996 1995 1994 ---------- ---------- ---------- Deferred income tax provision calculated using the Canadian federal and provincial statutory combined tax rate of 44.34%.... $ 6,233 $ 479 $ 834 Increase resulting from: Imputed preferred dividend................... 568 - - Non-deductible Canadian expenses............. 97 - - Decrease resulting from: Effect of lower income tax rates on United States income......................... (1,586) (112) (116) ---------- ---------- ---------- Total tax provision $ 5,312 $ 367 $ 718 ========== ========== ==========
The Company at December 31, 1996 had net operating loss carryforwards for U.S. tax purposes of approximately $14,417,000 and approximately $12,760,000 for alternative minimum tax purposes. The net operating losses are scheduled to expire as follows: ALTERNATIVE INCOME MINIMUM AMOUNTS IN THOUSANDS TAX TAX - ----------------------------------------------------- --------------- YEAR 2004 .................................$ 39 $ - 2005 ................................. 11 - 2006 ................................. 644 500 2007 ................................. 714 99 2008 ................................. 5,016 4,889 2009 ................................. 3,377 2,868 2010 ................................. 3,467 3,420 2011 ................................. 1,149 984 NOTE 5. SHAREHOLDERS' EQUITY Authorized The Company is authorized to issue an unlimited number of Common Shares with no par value, First Preferred Shares and Second Preferred Shares. The preferred shares may be issued in one or more series with rights and conditions as determined by the Directors. Common Stock Each Common Share entitles the holder thereof to one vote on all matters on which holders are permitted to vote. The Texas Pacific Group ("TPG") was granted a right of first refusal in the private placement (see below), to maintain proportionate ownership. No stockholder has any right to convert common stock into other securities. The holders of shares of common stock are entitled to dividends when and if declared by the Board of Directors from funds legally available therefore and, upon liquidation, to a pro rata share in any distribution to stockholders, subject to prior rights of the holders of the preferred stock. The Company is restricted from declaring or paying any cash dividend on the Common Stock by its bank loan agreement. 36 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 1996 Capital Adjustments During 1996, the Company issued 250,000 Common Shares for the conversion of the 6 3/4% Convertible Debentures of the Company and 75,000 Common Shares for the exercise of half of the Cdn. $8.40 Warrants ("Warrants"). On October 10, 1996, the Company effected a one-for-two reverse split of its outstanding common Shares. Effective October 15, 1996, all of the Company's outstanding 9 1/2% Convertible Debentures ("Debentures") were converted by their holders in accordance with their terms into 308,642 Common Shares. The holders of the Debentures also received an additional 7,948 Common Shares in lieu of interest which would have been due the holders absent an early conversion of the Debentures. At a special meeting held on October 9, 1996, the shareholders of the Company approved an amendment to the terms of the First Preferred Shares, Series A ("Convertible Preferred") to allow the Company to require the conversion of the Convertible Preferred at any time, provided that the conversion rate in effect as of January 1, 1999 would apply to any required conversion prior to that date. The Company converted all of the 1,500,000 shares of Convertible Preferred on October 30, 1996 into 2,816,372 Common Shares. The Company also issued an aggregate of 4,940,000 Common Shares on October 30, 1996 and November 1, 1996 at a net price of $12.035 per share as part of a public offering for net proceeds to the Company of approximately $58.8 million (the "Public Offering"). TPG purchased 800,000 of these shares at $12.035 per share. 1995 Private Placement of Securities In December 1995, the Company closed a $40 million private placement of securities with partnerships that are affiliated with the Texas Pacific Group ("TPG Placement"). The TPG Placement was comprised of: (i) 4.166 million common shares issued at $5.85 per share, (ii) 625,000 warrants at a price of $1.00 per warrant entitling the holder to purchase 625,000 common shares at $7.40 per share through December 21, 1999 and (iii) 1.5 million shares of $10 stated value Convertible Preferred. The Convertible Preferred shares were initially convertible at $7.40 of stated value per common share with such conversion rate declining 2.5% per quarter. The shares also had a mandatory redemption at a 63.86% premium at December 21, 2000. The Convertible Preferred were converted into 2,816,372 Common Shares on October 30, 1996. During the period that the Convertible Preferred were outstanding, the Company made a charge to net income to accrue the increase during the period in the mandatory redemption premium. The Company may force conversion of the $7.40 warrants issued in the TPG Placement after December 21, 1997, if the price of the Common Stock exceeds $10.00 per share for a period of 40 consecutive days. As part of the TPG Placement, TPG was granted certain "piggyback" registration rights which allow TPG to include all or part of the Common Shares acquired by TPG in any registration statement of the Company during the first two years. After the initial two years and until December 21, 2000, TPG may request and receive one demand registration statement to register the Common Shares acquired by TPG. TPG waived their "piggyback" registration rights for the Public Offering. The TPG agreement provides that TPG shall have the right, but not the obligation, to maintain its pro rata ownership interest (after the assumed exercise of their warrants and Convertible Preferred) in the equity securities of the Company, in the event that the Company issues any additional equity securities or securities convertible into Common Shares of the Company, by purchasing additional shares of the Company on the same terms and conditions. However, this right expires should TPG's share holdings represent less than 20% of the outstanding Common Shares. TPG waived its right to maintain its pro rata ownership with regard to the Public Offering. As part of the TPG Placement, Tortuga Investment Corp. was paid a financial advisor fee of 333,333 Common Shares of the Company. The sole shareholder of Tortuga Investment Corp. was appointed to the Board of Directors of the Company and elected Chairman upon the closing of the TPG Placement. 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 Warrants At December 31, 1996, 75,000 warrants were outstanding at an exercise price of Cdn. $8.40 expiring on May 5, 2000 and 625,000 warrants were outstanding at an exercise price of U.S. $7.40 expiring on December 21, 1999. Each warrant entitles the holder thereof to purchase one Common Share at any time prior to the expiration date. The Company has the option after December 21, 1997 to require exercise of the 625,000 warrants if the weighted average trading price of the Common Stock exceeds $10.00 per share for a period of 40 consecutive trading days. 75,000 of the Cdn. $8.40 warrants were exercised during 1996. Special Warrant Issues On April 25, 1995, the Company issued 614,143 Special Warrants at a price of $4.70 (Cdn. $6.50) per Special Warrant for gross proceeds of $2,750,000 (29,036 Common Share Purchase Warrants were issued to Southcoast Capital Corporation, as placement agent, in partial payment of their fee). Costs of the issue were $436,000, resulting in net proceeds to the Company of approximately $2,314,000. Each Special Warrant was exchanged, at no additional cost, for one Common Share of Denbury on August 11, 1995. Stock Option and Stock Purchase Plans The Company maintains a Stock Option Plan which authorizes the grant of options of up to 1,050,000 of Common Shares. Under the plan, incentive and non-qualified options may be issued to officers, key employees and consultants. The plan is administered by the Stock Option Committee of the Board. The Board of Directors of the Company have amended the Company's Stock Option Plan to (i) remove the 243,525 previously issued options which have been exercised from the plan and (ii) to increase the number of option shares authorized to be issued under the Plan from 1,050,000 to 2,000,000. This amendment is subject to shareholder and regulatory approval. Following is a summary of stock option activity during the years ended December 31, 1996, 1995 and 1994:
YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------------------- 1996 1995 1994 --------------------------- ----------------------- -------------------------- Weighted Weighted Weighted Average Average Average Number Price Number Price Number Price ---------- ---------- ----------- ---------- ---------- ----------- OUTSTANDING AT BEGINNING OF YEAR.... 731,925 $ 6.11 557,312 $ 6.30 541,312 $ 6.68 Granted............................. 525,500 8.96 274,500 5.89 138,750 5.64 Terminated.......................... (6,750) 6.28 (89,887) 7.79 (26,500) 9.35 Exercised........................... (197,675) 5.42 (10,000) 5.42 (96,250) 3.74 Expired............................. - - - - - - ---------- ---------- ----------- ---------- ---------- ----------- OUTSTANDING AT END OF PERIOD........ 1,053,000 $ 7.63 731,925 $ 6.11 557,312 $ 6.30 ========== ========== =========== ========== ========== =========== Options exercisable at end of year 532,375 $ 6.82 539,675 $ 6.19 487,937 $ 6.39 ========== ========== =========== ========== ========== ===========
Weighted Weighted OPTIONS OUTSTANDING AS OF Options Average Weighted Average Exercisable Average DECEMBER 31, 1996: Outstanding Price Remaining Life (yrs.) Options Price - --------------------------------- ------------ ---------- ----------------------- ------------ ---------- Exercise price of: $3.65 to $6.99 372,000 $ 5.79 4.3 305,250 $ 5.77 $7.00 to $9.99 444,625 7.78 6.5 175,906 7.70 $10.00 to $14.87 236,375 10.23 9.4 51,219 10.09
38 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 In February 1996, the Company also implemented a Stock Purchase Plan which authorizes the sale of up to 250,000 Common Shares to all full-time employees with at least six months of service. Under the plan, the employees may contribute up to 10% of their base salary and the Company matches 75% of the employee contribution. The combined funds are used to purchase previously unissued Common Shares of the Company based on its current market value at the end of the each quarter. The Company recognizes compensation expense for the 75% Company matching portion, which for 1996 totaled $147,000. This plan is administered by the Stock Purchase Plan Committee of the Board. NOTE 6. PRODUCT PRICE HEDGING CONTRACTS In October 1994, the Company entered into two financial contracts ("collars") to hedge 10,000 Mcf/d of natural gas production for calendar year 1995. The first natural gas contract for 8,000 Mcf/d of natural gas had a floor of $1.845 per MMBtu and a ceiling of $2.095 per MMBtu. The second natural gas contract was for 2,000 Mcf/d and had a floor of $1.775 per MMBtu and a ceiling of $1.885 per MMBtu. These contracts covered 75% of the Company's net revenue interest production in 1995 and increased oil and natural gas revenues by approximately $800,000 during such period. In addition, in 1995 the Company entered into two swap contracts for oil. The first oil contract was for 500 Bbls/d of oil at a price of $17.79 per barrel of oil commencing on February 1, 1995 and ending on January 31, 1996. The second oil contract was also for 500 Bbls/d of oil at a price of $18.83, for the period commencing on April 12, 1995 and ending on December 30, 1995. These contracts covered 43% of the Company's net revenue interest production for 1995 and decreased oil and natural gas revenues by approximately $47,000 during such period. The Company does not have any hedge contracts in place as of December 31, 1996. NOTE 7. COMMITMENTS AND CONTINGENCIES The Company has operating leases for the rental of office space, office equipment, and vehicles. At December 31, 1996, long-term commitments for these items require the following future minimum rental payments: December 31, AMOUNTS IN THOUSANDS 1996 -------------- 1997 .........................$ 442 1998 ......................... 411 1999 ......................... 166 2000 ......................... - 2001 ......................... - -------------- Total lease commitments $ 1,019 ============== The Company is subject to various possible contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies. The Company is not currently a party to any litigation which would have a material impact on its consolidated financial statements. However, due to the nature of its business, certain legal or administrative proceedings may arise in the ordinary course of its business. 39 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 NOTE 8. DIFFERENCES IN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES BETWEEN CANADA AND THE UNITED STATES The consolidated financial statements have been prepared in accordance with GAAP in Canada. The primary differences between Canadian and U.S. GAAP affecting the Company's consolidated financial statements are as discussed below. Loss on Extinguishment of Debt and Imputed Preferred Dividends The most significant GAAP difference relates to the presentation of the early extinguishment of debt and the imputed dividend on the Convertible Preferred. During 1996, the Company expensed $1,281,000 relating to the imputed preferred dividend, as required under Canadian GAAP. Under U.S. GAAP, this dividend would be deducted from net income to compute the net income attributable to the common shareholders. The Company also expensed its debt issue cost relating to the Company's prior bank credit agreements totaling $440,000 and $200,000 for 1996 and 1995, respectively. Under Canadian GAAP this is an operating expense, while under U.S. GAAP a loss on early extinguishment of debt is an extraordinary item. While net income per common share and all balance sheet accounts are not affected by these differences in GAAP, the net income for 1996 and 1995 under U.S. GAAP would be $10,025,000 and $714,000, respectively, while under Canadian GAAP the amounts reported were $8,744,000 and $714,000, respectively. Earnings Per Share In addition, the methodology for computing earnings per common share is not consistent between the two countries. For Canadian purposes, dilutive securities are only considered in the fully diluted presentation of earnings per share and the proceeds from such dilutive securities are used to reduce debt in the calculation. Under U.S. GAAP, the proceeds from such instruments are used to repurchase Common Shares, using a slightly different methodology for the primary and fully diluted calculations. For the years ended December 31, 1994 and 1995, the stock options, warrants, convertible debt and the conversion of the Convertible Preferred were either anti-dilutive or immaterial and were not included in the earnings per share under either GAAP calculation. For the year ended December 31, 1996, the Convertible Preferred was still anti-dilutive, but the stock options, convertible debt and warrants were dilutive and included in the earnings per share calculations, but with different results under the two respective GAAP's. Under U.S. GAAP for the year ended December 31, 1996, the primary earnings per share would be $.64 and the fully-diluted earnings per share would be $.63 as compared to the $.67 and $.62 as reported under Canadian GAAP. During 1996, the Company issued 4,940,000 Common Shares in a public offering and used a portion of the proceeds to retire bank debt. On a pro forma basis using U.S. GAAP and assuming that the Common Shares had been issued as of January 1, 1996 and the interest expense for 1996 relating to the bank debt was reversed, the primary earnings per share would be $.57 per share. No interest income was assumed in the pro forma calculation even though the proceeds from the equity issuance exceeded the bank debt that was retired. Stock-Based Compensation In 1995, the United States Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123 is effective for fiscal years beginning after December 31, 1995 and requires companies to use recognized option pricing models to estimate the fair value of stock-based compensation, including stock options. The Statement requires additional disclosures based on this fair value based method of accounting for an employee stock option and encourages, but does not require, companies to recognize the value of these stock option grants as additional compensation using the methodology of SFAS No. 123. The Company has elected to continue recognizing expense as prescribed by APB Opinion No. 25, "Accounting for Stock Issued to Employees", as allowed under SFAS No. 123 rather than recognizing compensation expense as calculated under SFAS No. 123. As such, the adoption of SFAS No. 123 during 1996 did not have any effect on the Company's consolidated financial statements. 40 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 The Company has two stock-based compensation plans as more fully described in Note 5. With regard to its stock option plan, the Company applies APB Opinion No. 25 in accounting for this plan and accordingly no compensation cost has been recognized. Had compensation expense been determined based on the fair value at the grant dates for the stock option grants consistent with the method of SFAS No. 123, the Company's net income and net income per common share would have been reduced to the pro forma amounts indicated below:
YEAR ENDED DECEMBER 31, ------------------------------- 1996 1995 ------------ ------------ NET INCOME: As reported (thousands)....................................................$ 8,744 $ 714 Pro forma (thousands)...................................................... 8,215 503 NET INCOME PER COMMON SHARE: As reported................................................................$ 0.67 $ 0.10 Pro forma.................................................................. 0.63 0.07 Stock options issued during period (thousands).................................. 526 275 Weighted average exercise price.................................................$ 8.96 $ 5.90 Average per option compensation value of options granted (1).................... 2.95 2.34 Compensation cost (thousands)................................................... 801 320 (1) Calculated in accordance with the Black-Scholes option pricing model, using the following assumptions; expected volatility computed using, as of the date of grant, the prior three-year monthly average of the Common Shares as listed on the TSE, which ranged from 32% to 67%; expected dividend yield - 0%; expected option term - 3 years, and risk-free rate of return as of the date of grant which ranged from 5.3% to 7.8%, based on the yield of five-year U.S. treasury securities.
Deferred Income Taxes Deferred income taxes relate to temporary differences based on tax laws and statutory rates in effect at the December 31, 1996 and 1995 balance sheet dates. At December 31, 1996, and 1995, all deferred tax assets and liabilities were computed based on Canadian GAAP amounts and were noncurrent as follows: December 31, ---------------------------- AMOUNTS IN THOUSANDS 1996 1995 ------------- ------------ Deferred tax assets: Loss carryforwards...................... $ (4,902) $ (4,511) Deferred tax liabilities: Exploration and intangible development costs....................... 11,645 5,942 ------------- ------------ Net deferred tax liability................... $ 6,743 $ 1,431 ============= ============ Recently Issued Accounting Standards The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants has adopted Statement of Position 96-1, "Environmental Remediation Liabilities," which provides guidance on the recognition, measurement, display and disclosure of environmental remediation liabilities. The Statement is effective for the Company's 1997 fiscal year. Management evaluated such Statement and believes that it will not have a material effect on the financial position or results of operations of the Company. 41 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 NOTE 9. SUPPLEMENTAL INFORMATION Significant Oil and Natural Gas Purchasers Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. The loss of any purchaser would not be expected to have a material adverse effect upon operations. For the year ended December 31, 1996, the Company sold 10% or more of its net production of oil and natural gas to the following purchasers: Natural Gas Clearinghouse (20%), PennUnion Energy Services (19%), Enron Oil Trading & Transportation (13%), and Hunt Refining (15%). Costs Incurred The following table summarizes costs incurred in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease, or otherwise acquire property, including both undeveloped leasehold and the purchase of revenues in place. Exploration costs include costs of identifying areas that may warrant examination and in examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering, and storing the oil and natural gas. Costs incurred in oil and natural gas activities for the years ended December 31, 1996, 1995 and 1994 are as follows: YEAR ENDED DECEMBER 31, ----------------------------------------- AMOUNTS IN THOUSANDS 1996 1995 1994 ----------- ----------- ----------- Property acquisition................ $ 48,856 $ 17,198 $ 6,736 Exploration......................... 4,592 1,687 1,796 Development......................... 33,409 9,639 8,371 ----------- ----------- ----------- Total costs incurred $ 86,857 $ 28,524 $ 16,903 =========== =========== =========== Property Acquisitions During April 1996, the Company closed an acquisition of additional working interests in five Mississippi oil and natural gas properties in which the Company already owned an interest, plus certain overriding royalty interests in other areas for approximately $7.5 million (the "Ottawa Acquisition"). The properties were acquired from Ottawa Energy, Inc., a subsidiary of Highridge Exploration Ltd. On April 17, 1996, Denbury entered into a purchase and sale agreement with Amerada Hess Corporation to purchase producing oil and natural gas properties in Mississippi, Louisiana and Alabama, plus certain overriding royalty interests in Ohio, for approximately $37.2 million (the "Hess Acquisition"). The Company funded this acquisition with bank financing from its NationsBank credit facility and closed this transaction during June 1996. These two acquisitions were accounted for under purchase accounting and the results of operations were consolidated during the second quarter of 1996. Pro forma results of operations of the Company as if the acquisitions had occurred at the beginning of each respective period are as follows:
Year Ended December 31, --------------------------- IN THOUSANDS, EXCEPT PER SHARE AMOUNTS 1996 1995 ------------ ----------- Revenues....................................................$ 61,573 $ 41,273 Net income.................................................. 9,820 899 Net income per common share................................. 0.75 0.13
In computing the pro forma results, depreciation, depletion and amortization expense was computed using the units of production method, and an adjustment was made to interest expense reflecting the bank debt that was required to fund the acquisitions. The pro forma results reflect an increase of $250,000 and $500,000 for 1996 and 1995, respectively, in general and administrative expense for additional personnel and associated costs relating to the acquired properties, net of anticipated allocations to operations and capitalization of exploration costs. The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Hess Acquisition by the Company and are presented on the full cost accrual basis of accounting. Depreciation, depletion, and amortization, allocated general and administrative expenses, interest expense and income, and income taxes have been excluded because the property interests acquired represent only a portion of a business and these expenses are not necessarily indicative of the expenses to be incurred by the Company.
YEAR ENDED DECEMBER 31, ------------------------------------ AMOUNTS IN THOUSANDS 1996 1995 1994 ---------- ---------- ---------- Revenues: Oil, natural gas and related product sales....... $ 20,165 $ 18,210 $ 17,787 Direct operating expenses: Lease operating expense......................... 6,302 7,888 6,598 ---------- ---------- ---------- Excess of revenues over direct operating expenses...... $ 13,863 $ 10,322 $ 11,189 ========== ========== ==========
The following represents the revenues and direct operating expenses attributable to the net interest acquired in the Ottawa Acquisition by the Company and are presented on the full cost accrual basis of accounting. Depreciation, depletion, and amortization, allocated general and administrative expenses, interest expense and income, and income taxes have been excluded because the property interests acquired represent only a portion of a business and these expenses are not necessarily indicative of the expenses to be incurred by the Company. YEAR ENDED DECEMBER 31, AMOUNTS IN THOUSANDS 1996 --------------- Revenues: Oil, natural gas and related product sales................$ 4,215 Direct operating expenses: Lease operating expense.................................. 760 --------------- Excess of revenues over direct operating expenses...............$ 3,455 =============== In November 1995, the Company acquired seven producing wells and certain non-producing leases in the Gibson/Humphreys Fields of Terrebonne Parish, Louisiana for approximately $10.2 million. NOTE 10. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) Net proved oil and natural gas reserve estimates as of December 31, 1996 and December 31, 1995 were prepared by Netherland & Sewell and the net oil and natural gas reserve estimates as of December 31, 1994 were prepared by The Scotia Group, Inc., both independent petroleum engineers located in Dallas, Texas. The reserves were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Oil and natural gas prices in effect as of the reserve report date were used without any escalation except in those instances where the sale is covered by contract, in which case the applicable contract prices including fixed and determinable escalations were used for the 42 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 duration of the contract, and thereafter the last contract price was used. Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. All of the reserves are located in the United States. Estimated Quantities of Reserves
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------- 1996 1995 1994 ---------------------- ---------------------- ---------------------- Oil Gas Oil Gas Oil Gas (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) --------- ---------- ---------- --------- --------- ---------- BALANCE BEGINNING OF YEAR................... 6,292 48,116 4,230 42,047 3,583 13,029 Revisions of previous estimates........ (490) 3,737 830 (1,620) (48) 2,827 Revisions due to price changes......... 1,053 402 - - - - Extensions, discoveries and other additions............................ 3,492 5,480 732 - 640 14,978 Production............................. (1,500) (8,933) (728) (4,844) (489) (3,326) Acquisition of minerals in place....... 6,205 25,300 1,228 12,533 544 14,539 --------- ---------- ---------- --------- --------- ---------- BALANCE AT END OF YEAR...................... 15,052 74,102 6,292 48,116 4,230 42,047 ========= ========== ========== ========= ========= ========== PROVED DEVELOPED RESERVES: Balance at beginning of year........... 5,290 34,894 3,755 35,578 3,418 12,303 Balance at end of year................. 13,371 58,634 5,290 34,894 3,755 35,578
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does not purport to present the fair market value of the Company's oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company's tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. 43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
DECEMBER 31, ---------------------------------------- AMOUNTS IN THOUSANDS 1996 1995 1994 ----------- ----------- ------------ Future cash inflows.................................................... $ 627,476 $ 214,932 $ 126,129 Future production costs................................................ (134,986) (56,323) (35,069) Future development costs............................................... (28,722) (16,154) (7,369) ----------- ----------- ------------ Future net cash flows before taxes .................................... 463,768 142,455 83,691 10% annual discount for estimated timing of cash flows............ (147,670) (45,490) (31,000) ----------- ----------- ------------ Discounted future net cash flows before taxes.......................... 316,098 96,965 52,691 Discounted future income taxes......................................... (74,226) (15,801) (5,763) ----------- ----------- ------------ STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS $ 241,872 $ 81,164 $ 46,928 =========== =========== ============
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
YEAR ENDED DECEMBER 31, ------------------------------------------- AMOUNTS IN THOUSANDS 1996 1995 1994 ----------- ----------- ------------- BEGINNING OF YEAR...................................................... $ 81,164 $ 46,928 $ 28,465 Sales of oil and natural gas produced, net of production costs......... (39,385) (13,243) (8,383) Net changes in sales prices............................................ 116,587 23,037 863 Extensions and discoveries, less applicable future development and production costs.............................................. 34,113 1,926 13,416 Previously estimated development costs incurred........................ 5,278 2,193 2,492 Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production................. 7,747 3,958 (2,914) Accretion of discount.................................................. 8,116 4,693 2,847 Purchase of minerals in place.......................................... 86,677 21,710 15,732 Net change in income taxes............................................. (58,425) (10,038) (5,590) ----------- ----------- ------------- END OF YEAR............................................................ $ 241,872 $ 81,164 $ 46,928 =========== =========== =============
UNAUDITED QUARTERLY INFORMATION The following table presents unaudited summary financial information on a quarterly basis for 1996 and 1995.
IN THOUSANDS EXCEPT PER SHARE AMOUNTS MARCH 31 JUNE 30 SEPT. 30 DECEMBER 31 - ------------------------------------------------- ------------------------------------------------------------------ 1996 Revenues $ 9,092 $ 11,682 $ 14,359 $ 18,516 Expenses 6,767 9,608 11,486 11,732 Net income 1,380 1,215 1,745 4,404 Net income per share (a) 0.12 0.11 0.14 0.25 Cash flow from operations (b) 6,065 7,238 8,464 12,373 1995 Revenues $ 4,381 $ 4,636 $ 4,841 $ 6,251 Expenses 3,723 4,583 4,554 6,168 Net income 435 35 190 54 Net income per share 0.08 0.00 0.02 0.00 Cash flow from operations (b) 2,112 1,913 2,234 3,135 (a) Due to the significant variances between quarters in net income and average shares outstanding, the combined quarterly income per share does not equal the reported earnings per share for 1996. (b) Exclusive of the net change in non-cash working capital balances.
44 Quarterly Stock Information Common Stock Trading Summary The following table summarizes the high and low last reported sales prices on days in which there were trades of the Common Shares on NASDAQ and on the TSE (as reported by such exchange) for each quarterly period for the last two fiscal years. The trades on NASDAQ are reported in U.S. dollars and the TSE trades are reported in Canadian dollars. The Company's Common Shares were first listed on NASDAQ effective August 25, 1995. As of February 1, 1997, to the best of the Company's knowledge, the Common Shares were held of record by approximately 1,200 holders, of which approximately 150 were U.S. residents holding approximately 72% of the outstanding Common Shares of the Company. No Common Share dividends have been paid or are anticipated to be paid. (See also Note 5 to the Consolidated Financial Statements).
NASDAQ (U.S. $) TSE (CDN $) HIGH LOW HIGH LOW - ----------------------------------------------------------------------------------------------------------- 1996 First quarter 7.88 6.25 10.80 8.30 Second quarter 10.75 8.50 14.50 12.00 Third quarter 13.50 10.00 18.10 12.70 Fourth quarter 15.25 12.50 20.95 17.00 - ----------------------------------------------------------------------------------------------------------- 1996 annual 15.25 6.25 20.95 8.30 - ----------------------------------------------------------------------------------------------------------- 1995 First quarter - - 7.80 6.60 Second quarter - - 8.70 7.00 Third quarter 6.75 5.32 8.70 7.00 Fourth quarter 6.25 5.50 8.70 7.10 - ----------------------------------------------------------------------------------------------------------- 1995 annual 6.75 5.32 8.70 6.60 - -----------------------------------------------------------------------------------------------------------
EX-21 4 EXHIBIT 21 EXHIBIT 21 LIST OF SUBSIDIARIES
JURISDICTION OF NAME OF SUBSIDIARY INCORPORATION STATUS - --------------------------------- ---------------------------- --------------------------------------------- Denbury Holdings Ltd. Province of Alberta Wholly owned subsidiary of Denbury Resources Inc. - holding company Denbury Management, Inc. State of Texas Wholly owned subsidiary of Denbury Holdings Ltd. - operating company Tallahatchie Resources, Inc. State of Texas Wholly owned subsidiary of Denbury Management, Inc. - dormant Denbury Marine, L.L.C. State of Louisiana Wholly owned subsidiary of Denbury Management, Inc. - marine company Brymore Energy Corp. State of Texas Wholly owned subsidiary of Denbury Management, Inc. - marketing company
EX-23 5 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in the Registration statement of Denbury Resources Inc. (formerly Newscope Resources Ltd.) on Form S-8 (Registration No.-333-1006) of our report dated February 21, 1997, with respect to the consolidated financial statements and schedule of Denbury Resources Inc. appearing in the Annual Report on Form 10-K of Denbury Resources Inc. for the year ended December 31, 1996. Deloitte & Touche Chartered Accountants Calgary, Alberta March 19, 1997 EX-27 6 FDS --
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE DENBURY RESOURCES INC. DECEMBER 31, 1996 FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000945764 Denbury Resources, Inc. 1000 US DOLLARS 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 1 13,453 0 15,549 0 0 29,002 166,137 (31,141) 166,505 16,520 0 0 0 130,323 12,181 142,504 52,880 53,649 0 35,879 1,721 0 1,993 14,056 5,312 8,744 0 0 0 8,744 .67 .62
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